Processes For Recovering Waste Heat From Gasification Systems For Converting Municipal Solid Waste Into Ethanol

ABSTRACT

Facilities and processes for generating ethanol from municipal solid waste (MSW) in an economical way via generating a syngas, passing the syngas through a catalytic synthesis reactor, separating fuel grade ethanol, extracting energy at particular strategic points, and recycling undesired byproducts.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to U.S. Provisional Application No.61/302,516, entitled “Process for Converting Municipal Solid Waste intoEthanol,” filed 8 Feb. 2010, the content of which is incorporated hereinby reference. This application is further related to U.S. patentapplication Ser. No. ______, (attorney docket number 051955-000008)titled “Product Recycle Loops In Process For Converting Municipal SolidWaste Into Ethanol,” and U.S. Utility patent application Ser. No.______, (attorney docket number 051955-000010) titled “Gas Recycle Loopsin Process For Converting Municipal Solid Waste Into Ethanol,” bothapplications filed currently herewith, and the entire disclosures ofboth of which are hereby incorporated by reference.

TECHNICAL FIELD

This subject matter relates generally to processes, systems, and plantsfor converting municipal solid waste into ethanol.

BACKGROUND

Municipal solid waste (MSW) includes all solid materials disposed bymunicipalities. While some of this waste is recycled, the majority istypically dumped in landfills, where it decomposes over a period ofdecades or even centuries. It has long been recognized, however, thatmunicipal solid waste contains organic materials that have energycontent. If MSW is left untreated in landfills, this energy contentdrained slowly from the landfill by bacterial processes, which not onlydissipate the concentrated energy, but also produce methane, which is astrong greenhouse gas. Some landfills have sought to collect thismethane, which may be used for fuel; however, the conversion to methanetakes place on long time scales, wastes much of the internal energy ofthe MSW, and is ineffective in recovering much of the available energycontent of the MSW.

The earliest and most common method of recovering the energy from MSW isincineration. Incineration includes the combustion of MSW orrefuse-derived fuel (RDF) to produce heat, which typically powers aturbine to produce electricity. Byproducts of incineration include flyash, bottom ash, flue gases, and particulates. Fly ash and bottom ashare typically discarded in land fills. Flue gases and particulates canbe scrubbed from the incineration flue stream prior to discharge intothe atmosphere. However, effective removal of all harmful flue streamcomponents can be prohibitively expensive.

Another method of recovering energy from MSW is pyrolysis, whichinvolves heating the organic portions of the MSW, so that thermallyunstable compounds are broken down and evaporate with other volatilecomponents. These volatile components form a pyrolysis gas that includestar, methane, aromatic hydrocarbons, steam, and carbon dioxide. Thesolid residue from pyrolysis process includes coke (residual carbon),which can then be burned or used for gasification. The byproducts ofpyrolysis are often more stable and less toxic than incinerator ash.

A related method for recovering energy from MSW is gasification. Thisinvolves converting at least a fraction of the MSW into a syngascomposed mainly of carbon monoxide carbon dioxide, and hydrogen.Gasification technology has existed for some two centuries. In thenineteenth century, the conversion of coal, often as a result of thecoking process, into “town gas” provided a flammable mix of carbonmonoxide (CO), methane (CH₄) and hydrogen (H₂) that was used forcooking, heating and lighting. During the twentieth century, more than amillion biomass gasifiers produced CO and H₂ to meet transportation andmobilization needs during World Wars I and II. With the discovery ofvast quantities of domestic natural gas after World War II, coal andbiomass gasification was no longer cost-competitive and disappeared asan industry. Modern researchers have struggled to make gasificationsystems cost effective.

Sometimes, gasification has been applied directly to the MSW; in othercases, the MSW is first pyrolyzed, then subject to a secondarygasification process. Gasification of MSW generally includes amechanical processing step that removes recyclables and other materialsthat have no energy content. Then, the processed feedstock is heated ina gasifier in the presence of a gasification agent (including at leastsome oxygen and possibly steam). Gasifiers may have a number ofconfigurations. For example, fixed-bed gasifiers place the feedstock ina fixed bed, and then contact it with a stream of a gasification agentin either a counter-current (“up draft”) or co-current (“down draft”)manner. Gasifiers may also use fluidized bed reactors.

Another method of treating MSW is treatment in the presence of oxygenwith a high-temperature plasma. Such systems may convert the MSW tosyngas, leaving vitrified wastes and metals as byproduct.

After gasification plasma treatment, the resulting syngas is typicallyscrubbed to remove at least some of the particulates, acid gases, andsoluble compounds. The scrubbing of syngas is much easier than scrubbingthe flue gas of an incinerator because of the much lower volume ofgases. The scrubbed syngas may be used to generate electricity bycombusting the syngas in a boiler and using the steam to produceelectricity, or by sending it to a combustion turbine that produceselectricity in single or combined cycle operations. Alternatively, thesyngas may be fed into a plant for the creation of synthetic fuels suchas hydrocarbons or alcohols. Synthetic fuels have the advantage thatthey may be transported long distances and used to generate energy in avariety of devices at locations other than the syngas processing plant.

To create hydrocarbons as synthetic fuels, a common method forconverting syngas into synthetic fuels is the catalytic Fischer-Tropschprocess. This process produces a mixture of hydrocarbons. Anotherpossibility is to create ethanol, methanol, n-propanol, and n-butanol,which may be incorporated into automotive fuels for use in existingautomobiles. There are several known methods for creating ethanol andother higher alcohols from MSW, including acid hydrolysis and variousbio-processes. However, these methods can often provide less favorableeconomics than desired. There are other catalytic processes that producelarge yields of ethanol or other alcohols. For example, U.S. patentapplication Ser. No. 12/166,212 (filed Jul. 1, 2008, and incorporated byreference herein) describes a catalytic process to convert a syngas intoa mixture of primarily methanol and ethanol. Because of tight energyconstraints and the low cost of fossil fuels, it has been difficult tomake these types of processes economically feasible. Creating ethanolfrom MSW efficiently is a difficult process that involves carefullymanaging feedstock quality, energy, syngas composition, syngas quality,product purification, and intermediate products. What is needed is anintegrated process capable of converting MSW into ethanol economically,with low waste that can be disposed of safely and economically, and withlow consumption of energy.

With the advent of higher gasoline prices, the development ofalternative and synthetic fuels continues to attract significantinterest. Synthetic fuels have the advantage that they may betransported long distances and may be used to generate energy at alocation other than the syngas processing plant. However, because oftight energy constraints and the historical low cost of fossil fuels, ithas been difficult to make synthetic fuel processes economicallyfeasible. For example, creating ethanol and other alcohols from syngasefficiently is a difficult process that involves carefully managingenergy, syngas, and other intermediate products. What is needed is aprocess capable of converting the waste materials such as MSW to syngas,and then syngas into alcohols economically and efficiently.

BRIEF SUMMARY

The present disclosure relates to facilities and methods for convertingorganic materials such as MSW into ethanol in an economical way. Invarious embodiments, the facilities may include a feedstock separator,configured to separate non-organic materials from a solid feedstock suchas MSW, thereby creating a solid processed feedstock. The facilities mayalso have a gasification unit configured to generate a, usually veryhot, from the processed feedstock. The heat from the hot syngas may bepassed through a waste heat recovery system, which preferably comprisesa heat exchanger or series of heat exchangers configured to generatesuperheated steam by cooling a stream comprising the primary syngas,thus outputting a cooled primary syngas stream. The facilities maypreferably include a steam turbine and generator configured to use thesuperheated steam to generate electricity.

In some embodiments, the facilities may also include one or more syngasscrubbers configured to remove or neutralize one or more unwantedcontaminants from the cooled primary syngas stream, such as particles,acid gases, catalyst poisons, etc., thereby to create a scrubbed syngas.To raise the pressure to a level appropriate for alcohol synthesis, thefacilities may include a syngas compressor.

The facilities may include one or more alcohol synthesis reactors,comprising a catalyst, preferably arranged as one or more catalyst beds,in fluid communication with the syngas compressor. The reactor(s) may beconfigured to take at least a portion of the compressed gas stream fromthe syngas compressor as an input (recycle gases may optionally also beincluded within the stream entering the reactor or reactors) and producean effluent. This effluent will preferably comprise unconverted syngasand a mixture of reaction products including alcohols and water. Torecovery various recycle and product streams, the facilities may includea purification unit configured to separate at least a portion of theeffluent into a number of streams comprising: an ethanol streamcomprising primarily ethanol; a stream comprising primarily water; amethanol stream comprising primarily methanol; and a heavy alcoholstream comprising primarily propanol and heavier alcohols.

In one embodiment, the facilities may include a quench recycle loop,which may include a mixing point upstream of the waste heat recoverysystem; the waste heat recovery system; and quench recycle streamwhereby cooled syngas is conveyed back to the mixing point upstream ofthe waste heat recovery system. This quench recycle stream may or maynot have passed through any of various scrubbers. The quench recyclestream may be flow-regulated based on the temperature at some pointupstream of the waste heat recovery system, so that the temperature ofsyngas entering the waste heat recovery system may be maintained near apredetermined temperature value.

Various additional embodiments, including additions and modifications tothe above embodiments, are described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated into thisspecification, illustrate one or more exemplary embodiments of theinventions disclosed herein and, together with the detailed description,serve to explain the principles and exemplary implementations of theseinventions. One of skill in the art will understand that the drawingsare illustrative only, and that what is depicted therein may be adapted,based on this disclosure, in view of the common knowledge within thisfield.

In the drawings:

FIG. 1 shows one embodiment of an overall process for converting MSWinto ethanol.

FIG. 2 shows an example of one embodiment of a gasification train forconverting MSW into syngas.

FIG. 3 shows one way to recover waste heat from a gasification effluentin accordance with the present disclosure.

FIG. 4 shows an overview of one embodiment of a syngas cleanup andcompression unit for use with the present disclosure.

FIG. 5 shows an illustrative example of a syngas blower for use with thepresent disclosure.

FIG. 6 shows one illustrative example of a syngas compressor for usewith the present disclosure.

FIG. 7 shows an illustrative example of an alcohol synthesis unit foruse with the present disclosure.

FIG. 8 shows an illustrative example of a solvent system for use withthe present disclosure.

FIG. 9 shows one possible embodiment of a purification system for usewith the present disclosure.

FIG. 10 shows an illustration of one embodiment of a mixed alcoholdegasser for use with the present disclosure.

FIG. 11 shows an illustration of one embodiment of an ethanol/heaviesseparator for use with the present disclosure.

FIG. 12 shows an illustration of one embodiment of a propanol/waterseparator for use with the present disclosure.

FIG. 13 shows an illustration of one embodiment of a methanol/ethanolseparator for use with the present disclosure.

FIG. 14 shows an illustration of one embodiment of a methanol/methylacetate separator for use with the present disclosure.

FIG. 15 shows an illustration of one embodiment of an ethanol drying andsulfur removal unit for use with the present disclosure.

FIG. 16 shows one embodiment of an electricity generation unit for usewith the present disclosure.

DETAILED DESCRIPTION

Various example embodiments of the present inventions are describedherein in the context of converting municipal solid waste into ethanolalong with possible co-products such as n-propanol and methanol.

Those of ordinary skill in the art will understand that the followingdetailed description is illustrative only and is not intended to be inany way limiting. Other embodiments of the present inventions willreadily suggest themselves to such skilled persons having the benefit ofthis disclosure, in light of what is known in the relevant arts, theprovision and operation of information systems for such use, and otherrelated areas. Reference will now be made in detail to exemplaryimplementations of the present inventions as illustrated in theaccompanying drawings.

In the interest of clarity, not all of the routine features of theexemplary implementations described herein are shown and described. Itwill of course, be appreciated that in the development of any suchactual implementation, numerous implementation-specific decisions mustbe made in order to achieve the specific goals of the developer, such ascompliance with regulatory, safety, social, environmental, health, andbusiness-related constraints, and that these specific goals will varyfrom one implementation to another and from one developer to another.Moreover, it will be appreciated that such a developmental effort mightbe complex and time-consuming, but would nevertheless be a routineundertaking of engineering for those of ordinary skill in the art havingthe benefit of this disclosure.

Throughout the present disclosure, relevant terms are to be understoodconsistently with their typical meanings established in the relevantart. However, without limiting the scope of the present disclosure,further clarifications and descriptions are provided for relevant termsand concepts as set forth below:

The term stream as used herein means any fluid or solid moving or enroute, directly or indirectly, from one location to another. A stream isstill a stream even if it is temporarily stationary for any length oftime. A conveyance means, means for conveying, conveyor, or pipe as usedherein means any mechanism known in the art for conveying fluid or solidmaterial directly or indirectly from one location to another (regardlessof whether the material is presently moving within the mechanism), whichmay also be synonymous with the term stream. It will be understood thatif this disclosure refers to a particular stream or conveyance means,this does not necessarily refer to a single pipe or other physicalconveyance. There are many equivalent ways to convey fluid or solidmaterial from one location to another, which may include the use ofmultiple fluid streams, conveyor belts, trucks or railcars, front-endloaders, or any other means of conveyance known in the art. All suchstreams or conveyance means are encompassed in this disclosure. In onenon-limiting example, if any two locations are in fluid communicationwith each other, then it may be considered that there is a conveyancemeans between the two locations.

Reference to a portion of a stream or material refers to any portion ofthe stream or material, including the stream or material in itsentirety. A portion of a stream or material may be mixed with othercompositions of matter and the mixture will be considered to comprisethe portion of the original stream or material.

The term mix or mixing means as used herein means any mechanism orprocess known in the art for mixing two compositions of matter. It mayinclude two or more inlets meeting at a single location to allow twofluid streams to flow together into a single outlet, or it may includeany type of mixer known in the art.

The term municipal solid waste (MSW) as used herein has the same meaningas the term is understood by one of skill in the art. An example of MSWis the solid waste that is obtained from the collection of municipaltrash. In its raw form, MSW need not be entirely solid, as it maycontain entrained or absorbed liquids, or liquids in containers or otherenclosed spaces. One of skill in the art will understand that MSW willhave a broad range of compositions, and that the source of MSW need notnecessarily be from a municipality. For purposes of this disclosure,other organic waste materials such as organic industrial waste,construction and demolition wastes, medical wastes, and various biomassmaterials such as vegetative matter, may be equivalent to MSW.

The term unit as used herein means part of a system, and may for examplecomprise a unit operation, a system or group of unit operations, aplant, etc.

The term boiler feedwater (BFW) as used herein has the same meaning asthe term is understood by one of skill in the art. Preferably, BFW maybe prepared, stored in a tank, and forwarded to boilers or other steamgenerating units within an industrial process. Preferably, BFW may beconditioned to prevent scale, corrosion, or other fouling, or to preventcaustic embrittlement, sedimentation, priming and/or foaming.

The term plasma melter refers to a device comprising a chamber wherein afeedstock is exposed to a plasma arc in conjunction with or without ajoule-heating element. Although many plasma units are possible,preferably, various embodiments of the plasma melter technology providedby InEnTec LLC may be used. These embodiments are described, forexample, in U.S. Pat. No. 5,666,891 and its related family of patents(including, without limitation, U.S. Pat. Nos. 5,707,508, 5,756,957,5,785,923, 5,798,497, 5,811,752, 5,847,353, 5,908,564, 6,018,471,6,037,560, 6,215,678, and 6,630,113), the disclosures of which areincorporated herein by reference. Reference herein to a plasma meltermay refer to any of these technologies described in these patents, ortheir equivalents, or modifications that would be obvious to one ofskill in the art.

The term thermal residence chamber (TRC) refers to a chamber that isconfigured to provide additional residence time, in the presence ofoxygen, to thermally crack hydrocarbons present in the syngas, and allowgasification and other gas phase reactions to go to completion or nearcompletion. Various example embodiments are described in the InEnTec LLCpatents listed above.

The terms syngas generation unit or gasification unit refer to a unit orset of units that generate syngas, which might for example include,without limitation, gasifers, plasma melters, plasma arcs, plasmatorches, combinations of gasifiers and plasma melters, steam reformers,pyrolysis reactors including for example slow pyrolysis or fastpyrolysis units, reformers, catalytic oxidizers, thermal oxidizers,reducing thermal oxidizers, and combinations of the above, possibly incombination with one or more TRCs. Each of the above components mayoperate in either a batch or continuous process.

The term syngas (synthesis gas) as used herein has the same meaning asthe term is used by one of skill in the art. For example, syngas maycomprise a combination of carbon monoxide, hydrogen, and possibly othercomponents such as, without limitation, water vapor, sulfur- ornitrogen-containing gases, carbon dioxide, methane, hydrocarbons, acidgases, and particulates.

The term separator as used herein refers to any process unit known inthe art for performing a separation process, including withoutlimitation distillation columns, membrane separation systems, ionexchange adsorption systems, thermal adsorption, pressure swingadsorption, molecular sieves, flash drums, absorption or adsorptioncolumns, wet scrubbers, Venturi scrubbers, centrifuges, chromatographs,or crystallizers. Separators may separate fluids or solids, or fluidsfrom solids.

The term in fluid communication with as used herein includes withoutlimitation both direct and indirect fluid communication, such as, forexample, through an intermediate process unit.

The term heat exchanger as used herein includes without limitation anyheat exchanger or heat exchange device known in the art, and morebroadly, any device which raises the enthalpy or internal energy of afirst composition of matter, decreases the enthalpy or internal energyof a second composition of matter, and transfers heat from the secondcomposition of matter to the first composition of matter. Various heatexchange means are disclosed herein, all of which are encompassed withinthis term. The term also includes combinations or series of multipleheat exchange means. It includes, without limitation, shell and tubeheat exchangers, air or “fin-fan” coolers, refrigeration units,chillers, cooling towers, steam generators, boilers, plate heatexchangers, adiabatic wheel heat exchangers, plate fin heat exchangers,fluid heat exchangers, waste heat recovery units of any kind, or phasechange heat exchangers of any kind They may operate in a countercurrent,parallel, crosscurrent configuration, or any other flow configuration,and may involve separation of two fluids or direct contact between twofluids, or the use of an intermediate fluid (such as water, hot oil,molten salt, etc.) to transfer heat from one fluid to another.

The term compressor as used herein includes anything that is understoodas a compressor in the normal sense of that term. In general, however,the term includes any device that raises a fluid from a first pressureto a second, higher pressure, either adiabatically or non-adiabatically.It may include any kind of compressor or pump, including withoutlimitation, centrifugal or axial, or positive displacement (such asreciprocating, diaphragm, or rotary gear). The term may also include oneor more stages of a multi-stage compressor. The term compressor used inthe singular may also refer to multiple compressors arranged in seriesand/or parallel.

The present disclosure describes various embodiments of a MSW to alcoholprocess that may include some or all of the following elements: agasification unit, a waste heat recovery unit, a syngas cleanup andcompression unit, an alcohol synthesis unit preferably containing one ormore catalytic alcohol synthesis reactors, a carbon dioxide removalunit, and purification unit for recovering and purifying ethanol from areactor effluent. An embodiment of the disclosure generates electricityfrom syngas and/or steam generated form waste heat. An embodiment mayrecycle methanol to the reactor, and may partially oxidize higheralcohols and methyl acetate as fusel oils in a gasification unit.

The creation of ethanol from MSW in this way has significant economicand environmental advantages. It reduces dependence on foreign oil,provides an energy efficient system with a very low emissions profile,reduces MSW entering landfills (thus dramatically reducing harmfulmethane gas emissions from landfills, and mitigating the need for new orexpanded landfills), reduces by displacement other greenhouse gasesassociated with the use of petroleum and coal derived fuel products, andcreates new green jobs.

FIG. 1 shows one embodiment of an overall process for converting MSWinto ethanol. First, MSW feedstock 1000 containing a heterogeneousvariety of municipal waste materials, or other waste materials orbiomass of a similar nature containing organic material (for example,various embodiments may use wood, bio-mass, straw, switch grass, orconstruction and demolition wastes), may be processed in a feedstockprocessing unit 10. In this unit, the waste material may be sized,separated, and processed to remove materials that are not useful in theprocess, or which might reduce its efficiency. For example, one mightwant to remove metals, inorganic materials, and wet materials such asfood waste or agricultural products. Such materials may, for example, berecycled or sent to a landfill or dried and sent to the gasificationunit along with other materials. Qualifying post-recycled or post-sortedfeedstock 1010 may be sent to a gasification unit 20. The gasificationunit may comprise one or more syngas generation units. In one embodimentof the gasification unit, glass cullet 1020 may be added to facilitatethe vitrification of inorganic non-metallic material, particularly ifthe gasification system includes a plasma melter. Oxygen 7510 and steampreferably generated from boiler feedwater (BFW) 7210 may be reactedwith the feedstock 1010 to produce syngas 2100. A nitrogen stream 7610may be used as a purge material, especially during start-up orshut-down. The gasification system may be configured, and conditionsprovided, so that at least the following gasification reaction Occurs:

C+H₂O→H₂+CO.

Simultaneously, conditions may preferably be provided so that thefollowing reversible “water shift” reaction reaches an equilibrium statedetermined mainly by the temperature of the gasifier, the pressurepreferably being near atmospheric:

CO+H₂O

CO₂+H₂.

Byproducts of the gasification unit 20 may include a glassified vitrate2005, which may preferably be sent to a landfill, and/or a metal 2006which may preferably be recycled. For safety and control purposes, thesystem may preferably be designed so that syngas 2100 may be quenched ifnecessary or desired by relatively low temperature syngas 4010, which ispreferably recycled from a location downstream of the waste heatrecovery system 30, preferably from syngas cleanup and compression unit40. In another embodiment, syngas 2100 may be quenched using a recyclestream of methanol, preferably methanol from purification unit 60.During this quenching process, methanol may be dissociated to hydrogenand carbon monoxide. In another embodiment, syngas 2100 may be quenchedby water.

Syngas 2004, which is either syngas 2100 or a mixture of mixture ofsyngas 2100 and 4010, may be passed through waste heat recovery system30, which in a preferred embodiment comprises one or more waste heatsteam generators (WHSG) to cool the syngas 2004 while generating steam3100 from BFW 7100. The steam 3100, preferably in addition to steam fromother parts of the process as well, may be sent to an electricitygeneration unit 70 preferably comprising a steam turbine.

Relatively cool syngas 3003 may be quenched with water in a directcontact Venturi scrubber and may be passed through syngas cleanup andcompression unit 40, where it may be cleaned of undesirable contaminantssuch as, for example, particles, acids and acid gases, mercury, lead,and other volatile metals, and compressed to a high pressure (syngas4034). A relatively low-pressure syngas recycle stream 4010 maypreferably be used, if necessary or desired, to quench the hot syngasstream 2100. Such quenching may be appropriate, for example, to keep thesyngas below the eutectic range of various minerals that may be presentin the fly ash so that those minerals will not coat boiler tubes withinthe waste heat recovery unit 30. Preferably, the temperature of syngasstream 2004 entering the waste heat recovery unit 30 will be in therange of about 649 to about 760° C. (about 1200 to about 1400° F.). Byrecirculating the cool syngas to quench the hot syngas, the energycontent of the syngas entering unit 30 may be preserved by transferringthe heat to the recycled gas stream rather than to an alternative streamsuch as water. However, the hot syngas stream 2100 may also be quenchedby water in an alternative embodiment.

High pressure syngas 4034 may be fed to the inlet to the alcoholsynthesis unit 50, which may produce one or more streams 5035 (liquid)and/or 5036 (gas) comprising mixed alcohols, and water stream 5037 to befed to a lower pressure purification unit 60. Preferably, at least partof the syngas (5002) prior to compression may be sent to electricitygeneration unit 70 which may contain a combustion turbine for burningsyngas purge gas 5002 from the alcohol synthesis recycle loop, and/ornatural gas 7450 in air to produce electricity.

In purification unit 60, syngas may be vented from the mixed alcoholstream and preferably recycled (syngas 6000) to the syngas cleanup andcompression unit 40. Water may be separated from one or more of themixed alcohols and some or all of it may preferably be recycled (stream6029) to the alcohol synthesis unit where it may be used to absorb mixedalcohols from the reactor effluent gas. In addition purification unit 60may separate methanol 6039, which may be recycled to the alcoholsynthesis unit 50 to be dissociated into carbon monoxide and hydrogen,and eventually converted to ethanol or may have an additional carbonatom inserted into the molecule along with additional hydrogen atoms toform ethanol. The purification unit may separate and collect heavyalcohols (preferably heavier than ethanol) as fusel oil 6040 forrecycling to the gasification unit 20. The resulting product ethanol6022 may be sent to an ethanol storage and handling unit 80. If theethanol is off-specification, it may preferably be recycled back (8010)to a location within the purification unit 60 and re-purified.

The ethanol storage and handling unit 80 may comprise any number ofstorage tanks, and facilities for testing, loading, and shipping ethanolto its final destination. It may also include facilities for denaturingthe ethanol such as by the addition of gasoline or other additives. Unit80 may also contain a pump for recycling any off-specification ethanol8100 back to a point upstream in the process where it can bere-purified.

Feedstock Processing

There may be several embodiments of a feedstock processing unit 10. Forexample, without limitation, the unit may process wood bio-mass, straw,switch grass, and other like biomass materials. Construction anddemolition wastes may also be processed. Preferably, the waste will havea high concentration of organic material, so that the vast majority ofnon-organic materials may preferably be removed in unit 10 withrelatively minimal processing effort. In a particular preferredembodiment, the MSW feedstock 1000 comprises the organic component ofMSW derived from the residual materials remaining after recyclingoperations are performed by material recovery facilities. This describedembodiment may also be applicable to other types of feedstock containingorganic materials, such as biomass or construction and demolitionmaterials. Feedstock may be drawn from solid waste material recoveryfacilities (MRFs). These facilities receive collected MSW, then sort andprocess the waste to remove commercially recyclable materials. Therecyclable materials may either be separated by the customersthemselves—typically at homes and offices—or by the MRFs.

The feedstock may be delivered to the feedstock processing unit 10 bytipper-type fixed floor transfer trailers or construction roll-offtrailers. The MSW may be shredded to reduce the maximum material size,preferably to less than about 4 inches, and processed through varioussolids handling equipment to remove the material that is not suitablefor gasification.

In a particularly preferred embodiment, feedstock trucks may be weighedwith a truck scale as they enter and exit the site to accuratelydetermine the quantity of MSW delivered. Delivery trucks may be of anycapacity, but may preferably have an MSW capacity of about 23 to about24 tons. In the preferred embodiment of this disclosure, approximately650 tons of MSW may be delivered per day. However, if a facility isdesigned to process more or less than this amount, one of skill in theart will know how to scale up the quantities, rates, and sizes ofequipment to efficiently handle that capacity.

In one embodiment, the feedstock may be deposited on a receiving floorand examined. Personnel may remove material volumes of food waste andother wet organics and send those materials to composting facilities, orthe process of removing such wet organics may be removed by automatedmeans known in the art. Personnel may also identify and removeoversized, prohibited, or undesirable objects while on the receivingfloor, or these objects may be removed by automated means known in theart. The remaining carbonaceous material will preferably be relativelydry, consisting of preferably 15 to 25% moisture.

A hydraulic-operated feedstock trailer tipper may be used to unload theMSW into a pile on the floor of a building housing feedstock processingfacilities. The building may preferably be sized to allow for thestorage of about one day of MSW. Undesirable material may be removedfrom the MSW pile using a front-end loader and placed in a rejectdumpster for return to the landfill.

A front-end loader may be used to load the MSW into a processing feedbin. This bin may preferably be sized to provide about 10 minutes of MSWfeed to the preparation system. A moving floor in the bin may transferthe raw feedstock to a scalping apron conveyor that meters the feedstockand deposits the feedstock on a flat conveyor. The flat conveyor mayprovide for a “pre-sort” station that permits the manual removal ofunwanted material (such as structural steel, propane bottles and PVC)that is readily spotted by operating personnel. The feedstock then fallsdirectly into a primary shredder. This shredder may reduce the size ofthe feedstock constituents to a maximum dimension of preferably about 8inches in any direction. The shredded feedstock may then be conveyed toa primary debris roll screen, where material smaller than preferablyabout 5.08 cm or 2 inches (the “2 inch minus processing train,”discussed below) may be removed from the main feedstock stream.

Preferably, the main feedstock material between about 5.08 and 20.32 cm(about 2 and 8 inches) in size leaving the primary debris roll screenmay be conveyed to a primary single drum separator where circulating airmay be utilized to separate the “light” feedstock material from “heavy”residue material such as rocks and concrete. The residue material may betransferred to a residue collection conveyer and then moved to transfertrucks for disposal. The main feedstock stream from the drum separatormay be conveyed to a primary cross belt magnet to remove the ferrousmaterial in the stream. The ferrous material collected by the magnet maythen be conveyed to dedicated rollaway containers.

The main feedstock stream that passes under the primary cross beltmagnet may then be combined with dry organic material (preferably in therange of about 1.27 cm to 5.08 cm or ½ to 2 inches in size) from the 2inch minus processing train on a conveyor. The combined stream may thenbe dropped onto the inlet conveyor for an eddy current separator wherenon-ferrous metals (mainly aluminum) may be removed from the feedstock.The non-ferrous material may be conveyed to dedicated rollawaycontainers.

The feedstock from the eddy current separator may be dropped onto aninlet conveyor for an optical sorter where PVC material may beidentified and separated from the feedstock using infrared detectors andblasts of high-speed air. The PVC material may be transferred to aresidue collection conveyer for disposal with the rest of the residue.The feedstock from the optical sorter may be flowed under a tertiarycross belt magnet for the final removal of ferrous material in thestream. The ferrous material collected by the magnet may be furtherconveyed to dedicated rollaway containers.

After passing under the tertiary cross belt magnet, the feedstock (nowpreferably relatively free of heavy inert material, ferrous andnon-ferrous metals, wet organic material and PVC) may be dropped onto asecondary debris roll screen. This secondary screen may preferablyseparate material smaller than preferably about 10.16 cm (about 4inches) from the larger material and deposit the smaller material on asmall material conveyor. The larger material may leave the secondaryscreen and fall into a secondary shredder where the size of the largerfeedstock constituents may be reduced to a maximum dimension ofpreferably about 4 inches in any direction. The freshly shreddedmaterial may be combined with the material from the small materialconveyor that bypassed the shredder. The combined feedstock, preferablyconsisting of constituents no larger than about 10.16 cm (about 4inches), may be conveyed into a feedstock storage building and depositedon the building floor or bailed for open storage.

Two inch minus processing train from the primary debris roll screen maybe deposited onto a primary vibratory screen where preferably about 0.95cm (about ⅜ inch) and smaller “gritty material” (i.e., rock, glass,metal, dirt, concrete, etc.) may be separated from the stream. Theapproximately 0.95 cm (approximately ⅜ inch) and smaller material may betransferred to a residue collection conveyer for disposal with the restof the residue. The remaining material (approximately 1.27 to 5.08 cm or½″ to 2″) may be transferred to a secondary single drum separator. Thedrum separator may preferably utilize circulating air to separate theorganic material from the heavier inert material. The heavy inertmaterial from the drum separator may be transferred to a residuecollection conveyer for eventual disposal. The primarily organicmaterial from the drum separator may drop onto a conveyor that passesthe material under a secondary cross belt magnet to remove the ferrousmaterial in the stream. The ferrous material collected by the magnet maybe further conveyed to dedicated rollaway containers. The remainingfeedstock may then be dropped onto the inlet conveyor for an airclassification unit to separate the wet (heavy) material from the dry(light) organic material.

The wet organic material may be sent to a separate system where it maybe dried and returned to the feedstock system upstream of the gasifiers.Alternatively, the wet material may be discarded. The dry organicmaterial from the air classification unit may be transferred, preferablypneumatically, to a rotary air separator, where the dry organic materialseparates from the transport air stream and is conveyed to join the mainfeedstock stream upstream of the eddy current separator (discussedabove).

The feedstock storage building may preferably be sized to store abouttwo days of gasifier feed (approximately 1000 tons in the preferredembodiment of this disclosure). A front-end loader may be used to placethe feedstock in storage piles and to load the processed feedstock intoa feedstock feed hopper. This feed hopper is preferably sized to provideabout 20 minutes of processed feedstock to the gasifiers at a feed rateof about 420 tons/day in the preferred embodiment of this disclosure. Amoving floor in the bin may transfer the processed feedstock to ascalping apron conveyor that meters the feedstock and may deliver it toa belt conveyor that weighs the feedstock utilizing a belt scale.Finally, the feedstock may be transferred to a distribution dragconveyor for distribution to one or more (and preferably three in thepreferred embodiment of this disclosure) gasifier metering bins.Feedstock that is not discharged into one of the bins may be droppedonto a return conveyor and sent back to the front end of thedistribution drag conveyor.

Each gasifier metering bin may, in the preferred embodiment of thisdisclosure, have a capacity of 250 cubic feet, and may be dedicated toone of the gasifier trains. The metering bins may preferably becone-shaped with their large diameter at the bottom to avoid bridging.Each bin may preferably have a live bottom screw that discharges thefeedstock to an airlock screw conveyor, where the feedstock may becompressed to form a “barrel-plug” to prevent hot gasses fromback-flowing from the gasifiers into the bins. The airlock screwconveyor may preferably be tapered along the length of the screw. A lumpbreaker at the discharge of each airlock screw conveyor may break up the“barrel-plug” before the feedstock is transferred to the airlockdischarge chute that feeds the gasifier. Each discharge chute maypreferably be equipped with an airlock gate valve that closes if theback flow of hot gases is detected.

The feedstock processing building and the processed feedstock storagebuilding may preferably be provided with dust collection, odor controland fire suppression systems. The outside conveying system thattransports the feedstock to the gasifiers may also be provided with adust collection system. Each dust collection system may preferablyconsist of a bag house and an induced draft fan. Plant air maypreferably be used to remove dust from the bags through a bag pulsingsystem. Dust removed from each the bag house may be sent to the residuecollection conveyer for disposal.

In one embodiment, dust may be extracted from various parts of theprocess. Once aggregated, the dust may then be combined or transportedwith the feedstock that goes into the gasification units.

Although the feedstock may vary greatly in composition, example nominalvalues for the composition of the material remaining after the feedstockis recycled and sorted are listed in Table 1 below.

TABLE 1 Example Ultimate Chemical Composition of Feedstock Approx.Weight Feedstock Constituent (Percent) C 45.0 H 5.5 O 17.0 N 0.3 S 0.3CI 0.3 Oxide 10.0 Metal 2.0 H₂0 19.6

The residual materials preferably excluded by the processing, storage,and handling process may include metals, rocks, dirt, concrete, PVC, andwet organic materials (wet food materials). Preferably, under normalconditions, the reject rate will run between about 10% and about 30% ofthe total feed rate to the material processing unit. All such materialsare solids at ambient conditions. Preferably, they will be individuallyseparated from the feedstock, deposited in a container, and transportedto a landfill or composting operation, or sent for recycling or disposaloff-site in accordance with applicable governmental regulations.

Gasification

In the preferred embodiment of this disclosure, the gasification unit 20includes three gasification trains, each with about 140 tons per dayprocessing capacity are provided to meet the total preferred plantprocessing capacity of about 420 tons/day. In light of this disclosure,one of skill in the art will know how to scale the facilitiesappropriately for different capacities.

FIG. 2 shows an illustrative example of one of these gasificationtrains. Each gasification train comprises one or more syngas generationunits, and preferably includes a gasifier, a plasma melter, and a TRC.In one embodiment, a feedstock 1010 enters a gasifier 20A which producesa first syngas 2001 and a non-gasified material 2000. The non-gasifiedmaterial 2000 passes in this embodiment to a plasma melter 20B intowhich is also fed glass cullet 1020, which produces vitrified inorganicmaterials and metal products (2005 and 2006, respectively) and a secondsyngas 2002. Syngas 2001 and syngas 2002 may in this embodiment becombined into syngas 2003 and sent to a TRC 20C, which produces a thirdsyngas 2100. Oxygen 7510 may be fed to the gasifier 20A, plasma melter20B, and/or TRC 20C. BFW 7210 may be boiled to steam 2100 and this steam(and/or, optionally, some other source of steam) may be fed to thegasifier and/or the plasma melter. In one embodiment, fusel oil 6040produced downstream in the alcohol synthesis process may be fed to theTRC.

In another embodiment, syngas 2100 may be at least partially quenched bya relatively cool syngas recycle stream 4010 from downstream in theoverall alcohol synthesis process, to produce a cooled mixture 2004. Ina preferred embodiment, there is a mixing point having one inlet forsyngas 2100, a second inlet is for syngas 4010, and an outlet for syngas2004. In the 2004 stream, there may be a temperature sensor and acontrol loop which opens a valve to the 4010 stream if the temperaturerises above a certain predefined level. In normal operation, syngas 2100may continue through the mixing point and becomes syngas 2100. If thetemperature sensor rises above a certain level, however, the valve tothe 4010 stream may open, and the relatively cool syngas 4010 may quenchthe hot syngas 2100. Alternatively, and even more preferably, the valveto the 4010 stream may be continuously controlled to maintain a mixedtemperature at some predefined temperature, preferably between about 649and 760° C. (about 1200 and 1400° F.), for the combined syngas stream2004.

Gasifier 20A preferably uses thermochemical technology in anoxygen-lean, non-combustion reducing environment. It is most preferablya down-draft partial oxidation gasifier, comprising a refractory linedvertical vessel. Preferably, the gasifier may convert at least about 80%by weight of the feedstock into syngas. In a particularly preferredembodiment, the gasifier 20A is a refractory-lined vertical vessel witha water-cooled grate in the lower section of the vessel to support afuel bed. The gasifier preferably operates at near atmospheric pressureand at temperatures preferably between about 849° C. and about 899° C.(about 1,560° F. and about 1,650° F.). Steam 2100 and oxygen 7510 may beintroduced into the gasifier to react with the feedstock to producesyngas and solid residue comprising inorganic and non-gasified organiccompounds. A grate in the bottom of the gasifier may allow thenon-gasified material 2000 to drop into the plasma melter 20B preferablylocated below the gasifier. In one embodiment, a mechanical rake maymove char, ash and other solids across the grate and into the plasmamelter. A small portion of the solid material (“fly ash”) may remainentrained with the syngas stream 2001 and may flow into the downstreamTRC 20C. A hood is preferably provided over the top of the gasifier tohelp provide for a safe working environment for operation andmaintenance activities above the gasifier. A gasifier cooling air blowermay pull ambient air under the hood and exhaust the heated air to theatmosphere at a safe location.

During start-up, the gasifier 20A may be preheated to its operatingtemperature before the gasification process can initiate. Therefore, thegasifier may be supplied with a down-fired gas burner designed to firethrough the wall of the vessel. A gasifier burner combustion Blowersupplies combustion air to the burners. The gasifier preheater systemmay be sized to allow the gasifier temperature to increase from ambientto operating temperature at the maximum rate allowed by the refractorylining.

In addition to the gasifier described above, other gasifiers are knownin the art, including various down-draft partial oxidation gasifierdesigns. One may select any number of such gasifiers for use inaccordance with this disclosure.

The gasifier and other syngas generation units preferably use at leastabout 99.5% pure oxygen, which may be prepared in an on-site cryogenicoxygen plant or other means that may be more energy efficient.Alternatively, liquid oxygen may be transported to the site, stored, andwithdrawn for use from a liquid oxygen storage tank.

If the gasification unit 20 uses a plasma melter 20B, glass cullet(ground glass) may be added to maintain the proper glass level withinthe chambers. The glass may in one embodiment be received in supersacksand bag handling structures provided to individually feed each gasifiertrain. Each bag handling structure may utilize a hoist and trolleysystem to lift a supersack from the ground and place it on top of itsdedicated discharge hopper. The supersack may manually be emptied intothe hopper using a hinged access door. A slide gate at the bottom of thehopper may then be manually opened to supply the glass to a feedingsystem which might be dedicated to a particular plasma melter.

A plasma melter accomplishes both gasification and vitrificationoperations. The non-gasified material and ash 2000 leaving the gasifiermay fall into the plasma melter chamber where it is exposed to aplasma-arc that provides the intense energy needed to rapidly gasify theremaining organic material. Steam and oxygen may be introduced into theplasma melter to react with the gasified organic material and producesyngas 2002. The vapor space within the chamber may preferably operateat an approximate temperature of 1,198.8° C. (approximately 2,190° F.).

Any glass-type materials entering the plasma melter chamber 20B from thegasifier 20A may be melted by the plasma-arc and fall to the bottom ofthe chamber to form a molten glass pool. Glass cullet and otherglass-forming additives may be added separately to the plasma melterchamber in order to maintain the desired molten glass pool level in theplasma melter. Metals that were not removed in the feedstock processingsection may also melted by the plasma-arc and form a separate moltenlayer in the bottom of the chamber under the molten glass. The mineralmaterial in the feed that is not melted by the plasma-arc may fall intothe molten glass pool to be vitrified in the glass waste product. Themolten glass and molten metal may independently be withdrawn from thebottom of the plasma melter chamber and processed by separate producthandling systems. The molten glass may preferably flow continuously ontoa frittering vibratory conveyor that cools the glass to approximately232° C. (approximately 450° F.) utilizing cooling water which fracturesthe glass into small pieces. The glass pieces then may preferably fallonto a wet conveyor that utilizes direct contact evaporativewater-cooling to cool the glass to approximately 121° C. (approximately250° F.) or less for disposal. The molten metal may be withdrawnintermittently and deposited into large refractory molds that may becooled with ambient air to cast the metal into ingots for disposal.

In one embodiment, any remaining inert material that enters the gasifierand plasma melter, including fines, grit and smaller inorganics that arenot screened out by the front-end processing system, may be expected tobecome encapsulated in a vitrified byproduct that is non-leachable andcan be recycled into road aggregate cement products or used for landfillcover.

DC power may be used to produce the plasma-arc for the plasma melter20B. The plasma-arc power may preferably be supplied through consumablegraphite electrodes that enter the top of the vessels. The graphiteelectrodes may be added in segments from outside of the vessels. The useof graphite electrodes may result in a plasma-arc system with anelectrical efficiency of about 98%. The DC power system may provide mostof the energy required for gasification of the waste that enters theplasma melter.

An independent AC power source may heat and maintain the molten glasspool temperature through electrodes positioned below the glass surface.The maximum operating temperature of the molten glass bath is preferablyabout 1,648.9° C. (about 3000° F.); however, lower operatingtemperatures may more preferably be maintained to maximize therefractory liner life. The AC power system may also used to maintain theplasma melter close to its operating temperature during temporaryshutdowns that can last from a few hours to weeks, if required. Bymaintaining the plasma melter near its normal operating temperature,short maintenance activities or intermittent operations may preferablybe accommodated without draining all of the glass resulting in a lengthystartup procedure. This operating mode may also preferably preserve therefractory life by reducing the number of thermal transients associatedwith startup and shutdown activities.

A hood may be provided over the top of the plasma melter to help providefor a safe working environment for operation and maintenance activitiesabove the plasma melter. A plasma melter cooling air blower may beprovided to pull ambient air under the hood and to exhaust the heatedair to the atmosphere at a safe location.

In addition to the plasma melter described above, any number of otherplasma melters may be used in conjunction with the other units describedin this disclosure.

The combined syngas stream 2003 from the gasifier 20A and plasma melter20B may be routed to a TRC 20C. Additionally, a fusel oil stream 6040from some location downstream of the gasifier unit 20 may be injectedinto any of the TRCs. If three TRCs are used in the process, thenpreferably, fusel oil may be injected into any two of the three TRCs.Injection of fusel oil stream 6040 serves to recycle the heavy alcoholcompounds produced in the reactors of the alcohol synthesis unit 50, andseparated in the purification unit 60, discussed below. The TRC 20C maypreferably be a refractory-lined cylindrical chamber that providesadditional residence time for syngas production in the presence ofoxygen. The oxygen 7510 may preferably be injected into the TRC throughside ports located just above the syngas 2003 inlet nozzle, for reactionwith the synthesis gas to generate heat to maintain the chamber at thedesired operating temperature. The reactions in the chamber maythermally crack the organic compounds present in the raw syngas 2003 andthe fusel oil 6040 to allow the gasification reaction to reach orapproach equilibrium.

During start-up, the TRC may preferably be preheated to operatingtemperature with a gas-fired burner similar to that described above forpreheating the gasifiers. A TRC preheater blower may supply combustionair to the burners. The TRC preheater may be mounted near the syngasinlet nozzle and preferably be sized to heat the TRC from ambient tooperating temperature at the maximum rate allowed by the refractorylining.

Waste Heat Recovery

In the preferred embodiment of this disclosure, the syngas 2100 comingfrom the gasification unit 20 is very hot, preferably approximately1,348.9° C. (approximately 2,460° F.), and may include a mixture ofhydrogen, carbon monoxide, carbon dioxide, methane, nitrogen, steam,acid gases, and particulates. In the preferred embodiment of thisdisclosure, the pressure of syngas 2100 is very roughly at or nearatmospheric pressure, although this pressure is not critical, and thesyngas can have a wide range of pressures. In one nonlimiting example,the pressure in 2100. Waste heat recovery unit 30 includes a mechanismfor recovering some of the heat from the hot syngas effluent and usingit to do work, preferably by converting it to steam and then toelectrical power in a steam turbine.

FIG. 3 illustrates a preferred embodiment of a way to recover heat fromthe gasification effluent. The hot syngas stream 2100 from gasificationunit 20 may combine with a cooled syngas quench stream 4010 that may berecycled from the discharge of the downstream syngas source atrelatively low temperature, preferably from the syngas cleanup andcompression unit 40. In a preferred embodiment, the amount of recycledsyngas may be continuously controlled to maintain a mixed temperature atapproximately 760° C. (approximately 1400° F.) for the combined stream2004, or each combined stream 2004 if there are multiple 2100 syngaseffluent streams. In the preferred embodiment, the temperature of stream2100 will be higher than 760° C. (1400° F.), such as roughly 1371° C. to1538° C. (roughly 2500° F. to 2800° F.), although the precisetemperature at the gasification outlet will depend upon a number offactors known in the art, and may be arbitrarily increase or decreasewithout changing the essential nature of the process.

Waste heat recovery may take place in a waste heat steam generator(WHSG) 30B. Preferably, each hot syngas stream 2100 from thegasification unit may have its own dedicated WHSG, when there aremultiple streams 2100, such as the three streams from three TRCsexemplified by the preferred embodiment of this disclosure. In someconfigurations, a plurality (e.g., three) of TRCs may merge their hotsyngas into a single stream which may pass through a single WHSG. EachWHSG 30B may preferably recover heat from the syngas stream 2004 bypreheating BFW 7100 in economizer 30E, generating saturated steam,preferably at about 800 psig in steam generator 30D, and superheatingthe steam in superheater section 30C, preferably along with steam 5100that may be produced by synthesis reactors in the alcohol synthesis unit50 and let down to match the pressure of steam drum 30A, or preferablyabout 55.2 bar (about 800 psig). Preferably all of the superheated steam3100 produced in WHSG 30B may be sent to electricity generation unit 70,which may contain a steam turbine generator to produce electrical power.WHSG 30B may preferably be designed for an exit temperature ofapproximately 176.7° C. (approximately 350° F.) so that the syngas 3003is cool enough to flow into a wet scrubbing section within the syngascleanup and compression unit 40, and hot enough to stay above the dewpoints of any acid gas components. A skilled engineer, based on thisdisclosure, may optimize this temperature and adjust it appropriately.Preferably, if multiple WHSG units are used, the syngas outlets for eachof them may be combined into a single syngas stream 3003.

Each WHSG may have a dedicated steam drum 30A and may preferably utilizenatural circulation for the steam production. Each drum may be suppliedwith one or more continuous and/or intermittent blowdown facilities 3101to maintain water quality.

Some particulate matter may fall out of the cooling syngas stream 2004and drop into the bottom of the WHSG. Additionally, slag or ash mightcollect on the tubes of the WHSG. Such solids may preferably be removedby blowing steam 7102 from soot blowers and collected in the bottom ofthe WHSG. In one embodiment, a stream of carbon dioxide 5015 extractedfrom syngas downstream in the overall process may be injected into theWHSG to help remove ash. The collected ash 3102 may periodically beremoved from the WHSG and conveyed to a disposal location.

In an alternative illustrative embodiment, waste heat may be recoveredby using the hot syngas in one or more heat exchangers to heat oil,which may be circulated through a loop to a steam generator, which steammay them be used to generate electricity. In this embodiment, the streamof hot oil may be recirculated via a pump, and the resulting hot oil maybe passed through a steam generator and hot oil cooler and stored in ahot drum before being recirculated through the loop.

Syngas Cleanup and Compression

After recovering waste heat in unit 30, the syngas may pass to syngascleanup and compression unit 40, where it may be compressed and cleanedof undesirable contaminants such as, for example, particles, acids,mercury, and/or hydrochloric acid (HCl).

FIG. 4 is an overview illustration of a possible syngas cleanup andcompression unit 40. Syngas 3003 from the waste heat recovery unit 30may contain particulate matter and chemical constituents that couldimpact the required metallurgy of downstream equipment and poisoncatalysts used for ethanol synthesis. Examples of such contaminants,which are preferably removed in the unit 40, are ash particulates, heavymetals such as mercury (Hg), lead (Pb) and chromium (Cr), and acidiccompounds such as hydrogen chloride (HCl) and hydrogen sulfide (H₂S).

Syngas 3003 may flow into a Venturi scrubber 40A. The scrubber mayutilize a circulating water stream to cool the syngas to its saturationtemperature and remove preferably at least about 99.9% of the ashparticulates and metals. In addition, the Venturi Scrubber may alsoserve as a first-stage acid gas scrubber. The circulating water solutionand the syngas stream may be separated in the separator section of thescrubber. The Venturi scrubber recirculation pump 40C may take suctionfrom the bottom of the separator section and pump the water back to thescrubbing section. A bleed stream 4002 from the discharge of the pumpmay be sent to a wastewater storage tank to remove solids and neutralizeacidic components in the system. Reclaimed water 7110 may be added tothe system in the separator section of the Venturi scrubber to maintainthe liquid inventory.

The syngas 4000 from the Venturi scrubber 40A then may flow to an acidgas scrubber 40D, which may in one preferred embodiment comprise astatic mixer section on top of a knockout drum. Circulating caustic orother alkaline solution such as hydrated lime may combine with syngasstream 4000 and the mixture may flow down through the static mixer toremove acidic compounds from the syngas. The preferably brief contacttime between the syngas and the alkaline solution in the static mixermay achieve an HCl content of less than about 1 ppm in the treatedsyngas stream 4003 while minimizing the consumption of the alkalinesolution resulting from the undesirable removal of carbon dioxide (CO₂).The treated syngas 4003 may exit the top of the knockout drum and flowto a system of one or more syngas blowers within a syngas blower unit40E. An alkaline solution circulation pump 40D may be utilized tocirculate the alkaline solution from the bottom of the drum back to theinlet of the static mixer. Fresh alkaline agent 7010 may be added to thecirculating solution to maintain a predefined pH range, and partiallyspent solution 4005 may be purged from the system to maintain a constantlevel in the knockout drum. The alkaline solution purge stream 4005 maybe sent to a wastewater storage tank, where it may preferably assists inthe neutralization of the acidic blowdown stream 4002 from the Venturiscrubber.

The supply of alkaline solution may preferably comprise a concentratedsolution of approximately 50 wt % caustic which is kept in storage in atank, or lime which may be in hydrated or anhydrous form. To dilute thealkaline solution to the desired concentration, a specified amount ofTRIGID water may be added to the tank. A pump may then be used tocirculate the solution through a cooling device, preferably a heatexchanger using cooling water, and a jet mixer located inside the tankto homogenize the diluted solution and remove heat generated by thedilution process. After mixing is complete, the supply of fresh alkalinesolution to the syngas cleanup and compression unit 40 may be resumedusing a caustic supply pump.

Syngas 4003 from the acid gas scrubber 40B may flow to a syngas blowerunit 40E, an example of which is described below. The syngas outlet ofblower 40E may be split into net syngas stream 4009 which may pass to asyngas compressor 40F, and one or more syngas quench streams 4010, whichmay be used as described above to quench the hot gasifier syngaseffluent.

Syngas 4009 may be compressed to high pressure in a syngas compressorsystem 40F. In one illustrative embodiment of a suitable syngascompressor, the net syngas stream 4009 may be compressed fromapproximately 15 psig for syngas 4009 to approximately 100 bar(approximately 1450 psig) for syngas 4032. In another higher-pressureembodiment, the pressure of syngas 4032 may be in the range of about103.4 to 151.7 bar (about 1500 to about 2200 psig). The pressure instream 4032 may be roughly about the same pressure as the reactor(s) inthe alcohol synthesis unit 50. In one embodiment, the pressure in thereactor(s) may be controlled by manipulating the power of the syngascompressor 40F through any control means known in the art. Part of thehigh pressure syngas 4032 leaving the syngas compressor 40F maypreferably be drawn off as a compressor spillback stream 4200, which mayrecycle to the syngas blower 40E, preferably to control the pressure ofthe syngas inlet 4009. The suction pressure of syngas 4009 at the inletof the syngas compressor, which is preferably essentially the same asthe discharge pressure of the syngas blower, may in one embodiment bemaintained at approximately 1 bar (approximately 15 psig) by spillbackcontrol from the outlet of the syngas compressor to the outlet of thesyngas blower. In this preferred embodiment, maintaining 1 bar (15 psig)at the discharge of the syngas blower may provide sufficient pressure tosend cooled quench gas 4010 to the inlet of the waste heat recovery unit30.

Syngas outlet 4034, representing whatever of syngas 4032 that is notrecycled to the outlet of the syngas blower, is the outlet of the syngascleanup and compression unit 40, which may flow to the alcohol synthesisunit 50.

FIG. 5 is an illustrative example of a syngas blower 40E. Syngas 4003from the acid gas scrubber 40B may preferably flow directly to thesuction of the first of one or more parallel syngas blowers, which maycontain multiple stages. In one embodiment, two rotary-type compressors42E and 42F may operate in parallel, with each preferably sized forabout 50% of the design flow rate. The discharge from each machine mayflow through syngas blower interstage coolers 42I and 42J utilizingcooling water. The cooled parallel streams may combine and flow to acommon syngas blower interstage knock-out drum 42M. Any condensed liquid4007 from the intercoolers may be separated from the gas stream inknock-out drum 42M and recycled back to the Venturi scrubber 40A. Thesyngas stream from knock-out drum 42M may split and flow to the suctionof a second set of compression stages of syngas blowers. Similar to thefirst stage, two rotary-type compressors 42G and 42H may operate inparallel with each preferably sized for approximately 50% of the designflow rate. The discharge from each machine may flow through syngasblower after coolers 42K and 42L that utilize cooling water. The cooledparallel streams may combine (4008) and flow to a common syngas blowerknock-out drum 42N. This drum may also preferably receive a compressorspillback stream 4200 from a syngas compressor 40F, and/or a flash gasstream 5004 from a location downstream in the overall process,preferably in the alcohol synthesis unit 50. Any condensed liquid 4013from the after coolers may be separated from the gas stream in knock outdrum 42N. Liquid 4013 may form a part of any condensed liquid 4007 fromany knock-out drums within the syngas blower system 40E, and all suchliquid 4203 may preferably be recycled back to Venturi scrubber 40A. Inone embodiment, compressors 42E, 42F, 42G, and 42H may beinternally-geared centrifugal compressors.

At the outlet of syngas blower knock-out drum 42N, the compressed streammay be spilt into the net syngas stream 4009, a compressor spillbackstream 4201 and one or more syngas quench streams 4010, which may beused as described above to quench the hot gasifier syngas effluent. Thenet syngas gas stream 4009 may flow directly to syngas compressor 40F.The compressor spillback stream 4201 may be sent back to the suction ofthe first stage (e.g., 42E and/or 42F) of the syngas blower. The flowrate through a spillback control valve 42P may preferably beautomatically controlled to maintain an operating pressure of at leastatmospheric pressure, or preferably approximately 1 psig, as syngas 4006enters the first stage of syngas blowers (e.g., 42E and/or 42F). Thiscontrol point may help ensure that the lowest operating pressure in thesystem is maintained slightly above atmospheric pressure and does notdrop to a vacuum condition.

FIG. 6 is one illustrative example of a syngas compressor 40F. The netsyngas stream 4009 may be compressed from approximately 1 bar toapproximately 100 bar (approximately 15 psig to approximately 1450 psig)by 5 reciprocating stages of compression in a syngas compressor. Theprecise pressure to which the stream is raised will be dictatedprimarily by the desired equilibrium conditions for the reactors in thealcohol synthesis unit 50. The syngas may flow to the first stage 41A ofthe syngas compressor where it may be compressed to approximately 3.4bar (approximately 50 psig) and then cooled in the syngas first stageintercooler 41B preferably utilizing cooling water. Any liquid 4204 thatcondenses in the intercooler may be knocked out in the syngas compressorfirst stage knock-out drum 41C and preferably recycled back to Venturiscrubber 40A. The syngas then may flow to a second stage 41D of thesyngas compressor where it may be compressed to approximately 8.9 bar(approximately 130 psig). After the second stage of compression, the hotsyngas may preferably be sent to a series of guard beds (e.g., 41E, 41F,and/or 41G) to remove traces of mercury, chlorine, and other catalystpoisons that may be present in the gas stream. The treated syngas maythen return to the compression section and be cooled in a syngascompressor second state intercooler 41H preferably utilizing coolingwater. Any liquid 4204 that condenses in the intercooler may be knockedout in a syngas compressor second stage knock-out drum 41I and recycledback the Venturi scrubber 41A.

The syngas then may flow to a third stage 41J of the syngas compressorwhere it may be compressed to approximately 20.7 bar (approximately 300psig). After compression the gas may be cooled in a syngas compressorthird stage intercooler 41K preferably utilizing cooling water. Anyliquid 4204 that condenses in the intercooler may be knocked out in asyngas compressor third stage knock-out drum 41L and preferably recycledback the Venturi scrubber 40A. The syngas may then flow to a fourthstage 41M of the syngas compressor where it may be compressed toapproximately 44.5 bar (approximately 645 psig). After compression thegas may be cooled in a syngas compressor fourth stage intercooler 41N,preferably utilizing cooling water. Any liquid 4204 that condenses inthe intercooler may be knocked out in the syngas compressor fourth stageknock-out drum 41P and preferably recycled back to Venturi scrubber 40A.Finally, the syngas may flow to a fifth stage 41Q of the syngascompressor where it may be compressed to approximately 98.9 bar(approximately 1435 psig) and then cooled in a syngas compressor fifthstage aftercooler 41R, preferably utilizing cooling water. Any liquid4204 that condenses in the aftercooler may be knocked out in a syngasCompressor fifth stage knock-out drum 41S and preferably recycled backto Venturi scrubber 40A. The outlet 4032 to drum 41S in this examplewill be compressed syngas.

At some point in the syngas cleanup and compression unit 40, preferablyduring an intermediate stage of compression within the syngas compressorunit 40F, the main syngas stream may be passed through a system forremoving potential catalyst poisons. In one embodiment, syngas stream4018 from syngas compressor second stage 41D may flow through one ormore catalyst poison separation units prior to the final stages ofcompression. In a preferred embodiment, syngas 4018 flows through threeguard beds. The first vessel 41E may be a mercury guard bed designed toremove mercury and other volatile metals. The second vessel 41F may bethe chlorine guard bed, designed to remove HCl, acid gas components, andother potential catalyst poisons. The final vessel 41G may be a combinedguard bed designed to remove catalyst poisons that have broken throughthe first two beds. During normal operation, the syngas may flow throughall three guard beds in series. If a breakthrough is detected at theoutlet of either of the two primary guard beds, both primary guard beds41E and 41F may be temporarily bypassed to allow for adsorbentreplacement, with the combined guard bed 41G remaining online to protectthe downstream synthesis catalyst. The combined guard bed 41G may alsobe temporarily bypassed (4202) to allow periodic replacement ofadsorbent to ensure that it is always available to protect thedownstream catalyst. The two primary guard beds 41E and 41F maypreferably be sized to provide an estimated adsorbent life of about 1year, while the combined guard bed 41G may preferably be designed tolast several years, given that it normally operates downstream of theprimary beds. Before returning to the syngas compression section, thesyngas may flow through a syngas guard bed filter 41T to remove anycatalyst fines from the gas stream.

Alcohol Synthesis

After passing through a syngas cleanup and compression unit 40, thecleaned and compressed syngas 4034 may pass to an alcohol synthesis unit50, where alcohol may be generated, preferably through a catalyticreactor.

FIG. 7 shows an illustrative example of an alcohol synthesis unit 50.Compressed syngas 4034 from the syngas cleanup and compression unit 40may preferably be combined with a recycle gas stream 5032 containingunreacted syngas from a reactor effluent stream, and fed to a solventsystem 50A, in which carbon dioxide may be removed from the compressedsyngas and recycle syngas streams. Reject gas containing CO₂ and H₂₅ maybe fed to one or more sulfur guard beds 50B and/or 50C, as will bediscussed In the preferred embodiment of this disclosure, the solventsystem is intended primarily to remove carbon dioxide, while sulfurremoval is incidental to CO₂ removal. In alternative embodiments, wherethe catalyst in reactor 50H does not require a significant amount ofsulfur, removal of sulfur within the recycle stream may be moreimportant.

Outlet sour gas stream 5010 may primarily comprise CO₂, and may also beexpected to comprise at least a small amount of H₂S. In a preferredembodiment, stream 5010 may be sent to sulfur guard beds 50B and 50C toremove the H₂S from the stream. The two guard beds preferably may bepiped in a lead/lag configuration to allow for on-line replacement ofspent adsorbent. The treated CO₂ reject gas 5015 from the guard beds maybe utilized in the ash removal systems for the waste heat recovery unit30, as discussed above, or vented to the flare header on pressurecontrol.

Some of the gas 5002 which may include syngas as well as methane,ethane, and other hydrocarbons, may be purged from the recycle loopstream after leaving the solvent system 50A, to be sent to theelectricity generation unit 70 which may preferably contain a combustionturbine for generating electricity. In other embodiments, the gas stream5002 may be fed to a boiler that may be used to generate steam thatwhich would subsequently be used to generate electricity. The remainingrecycle loop syngas 5001 may flow to a recycle compressor suction drum50D. Any liquid 5101 that may collect in the bottom of the drum may beexpected to potentially contain solvent, and may therefore be sent tothe solvent system to recover the solvent. The syngas 5102 then may flowto one or more recycle compressors 50E. Preferably, the recyclecompressor(s) 50E may boost the operating pressure from about 98.6 barto about 105.8 bar (about 1430 psig to about 1535 psig). In a preferableembodiment, two 100% reciprocating machines (operating in parallel) maybe provided to ensure the reliability of the syngas recycle service. Thesuction pressure may be maintained at approximately 98.6 bar(approximately 1430 psig) by spillback control through a recyclecompressor spillback cooler 50N that preferably utilizes cooling water.

From recycle compressor(s) 50E, the combined recycle gas stream andfresh feed syngas 5017 may flow to an ethanol synthesis feed/effluentexchanger 50F, where it may be heated by hot reactor effluent 5026 fromone or more ethanol synthesis reactor(s) 50H. The syngas may then becombined with recycled methanol 6039 from purification unit 60, and thecombined stream may be heated in a reactor feed heater 50G to thedesired reactor inlet temperature (which may, in one embodiment, beabout 315.5° C. or 600° F.) by heat exchange with superheated steam3650. The heated syngas 5020 then may flow to preferably tubular-typeethanol synthesis reactor(s) 50H, described below, which convert syngasinto ethanol, other alcohols, water, and possibly other relatedbyproducts. While the specific illustrated embodiments and foregoingdescription herein focus on creating ethanol from syngas, those of skillin the art will recognize that other alcohols may be produced if desiredby modifying the teachings of this disclosure to isolate another alcoholproduct from the reactor effluent stream.

In one embodiment, a small amount of sulfiding agent (preferablydimethyl disulfide) 5021 may be added to the syngas upstream of thereactors to achieve a sulfiding agent concentration of some predefinedconcentration that might be needed in any particular embodiment tomaintain catalyst activity. The concentration of the sulfiding agent mayin one embodiment be between about 20 to about 150 ppm, and preferablyin the range of about 50 to about 75 ppm, on a molar basis. The additionof a sulfidization agent within the preferred range may have thebenefits of reducing cracking of methanol to methane and carbon dioxide,and increased methanol and ethanol formation.

The sulfiding agent may, for example, be stored in a tote tank andinjected into the syngas using a sulfiding agent injection pump. Theconcentration of the sulfiding agent within the syngas may be controlledin any way known in the art; for example, the concentration may bemeasured by a total sulfur analyzer, and then the rate of injection intothe stream may be varied according to a feedback control loop. Varioussulfur analyzers, including total sulfur analyzers, are known in theart. The sulfiding agent may be injected by any means known in the art,including pumps, syringes, pistons, gravity feed, etc.

Most of the reactions that may occur in the reactor(s) 50H areexothermic. The heat of reaction may be removed from the reactors bycirculating boiler feed water around the reactor tubes and using theheat of reaction to produce steam 5100. One or more steam drums 50P mayseparate the steam from the circulating water, and in one embodiment maybe shared by all of the reactors. One or more steam drum circulationpumps 50Q may be provided for the circulating water service. In oneembodiment, each pump may be designed for 50% of the total designcirculation rate and two pumps may operate continuously (the third pumpmay be used as a spare). Operating two 50% pumps may ensure that theloss of a single operating pump does not result in the loss of watercirculation to the reactors. The operating pressure in the steam drummay be automatically adjusted so that the corresponding steam generationtemperature provides the proper heat transfer rate required to maintainthe desired reactor outlet temperatures, which in a preferred embodimentmay be about 350° C. (about 662° F.). In one embodiment, the pressure inthe steam drum 50P may vary between approximately 82.7 and 124.1 bar(approximately 1200 and 1800 psig) depending upon the operatingconditions. The high pressure steam 5100 (preferably all of it) leavingthe reactor steam drum 50P may be let down to approximately 55.2 bar(approximately 800 psig) and sent to the waste heat recovery unit 30,where it may in one embodiment be superheated by absorbing heat from thegasifier effluent.

Boiler feed water 5103 that has preferably been preheated in anotherpart of the overall process may be added to steam drum 50P to maintainits operating level. A continuous blowdown stream may be taken from thesteam drum and intermittent blowdown streams may be taken from the steamdrum 50P and the reactors 50H to maintain the water quality. Thecontinuous and intermittent blowdown streams may be routed to blowdowndrums.

The reactor effluent streams 5026 from one or more reactor trains may becombined and flow through an ethanol synthesis feed/effluent Exchanger50F to partially cool the effluent stream. The reactor effluent 5028then may flow through an absorber feed cooler 50J where it may be cooledby ambient air, and then through an absorber feed trim cooler 50K whereit may be cooled by cooling water before entering a mixed alcoholabsorber 50L. The alcohol absorber 50L may preferably be a frayed columnthat may utilize a primarily recycled water stream to absorb the alcoholcompounds from the reactor effluent stream 5031. The remaining gasstream 5032 exiting the top of the alcohol absorber may become becomesthe recycle gas stream that may be sent back to the upstream processwhere may be combined with the fresh feed syngas stream 4034 at theinlet to the Solvent System 50A.

An absorber water feed drum 50T may receive recycle water 6029 from thepurification unit 60 that may have been cooled in the tube side of anabsorber bottoms/water exchanger 50R. However, a portion of the recyclewater may be purged to maintain the quality of the recycle water. Theabsorber water feed drum 50T may also receive fresh demineralized water5104 to maintain the level in the drum. An absorber water feed pump 50Smay take suction from the drum 50T and transfer the water to the top ofmixed alcohol absorber 50L. Absorber water feed drum 50T may alsoprovide a small water slipstream 5037 from the discharge of the absorberwater feed pump 50S, which may be used for degassing the mixed alcoholsin the purification unit 60, as discussed below.

The mixed alcohol stream 5033 from the bottom of the absorber may besent to an absorber flash drum 50M where preferably the majority of thegasses absorbed in the liquid stream may be flashed off. The flashed gas5036 may be routed directly to purification unit 60, while the mixedalcohol liquid 5034 may be preheated in the shell side of the absorberbottoms/water exchanger 50R before being routed (5035) to purificationunit 60. The flash drum 50M may provide a safety break between thehigh-pressure syngas section and the low-pressure alcohol purificationsection. The pressure drop may be effected by any means known in theart, including providing resistance to flow through friction, such asvia a throttling valve, or by extracting work energy from a stream fromthe high-pressure section. One might expect a large volume of vapor tobe associated with a vapor-breakthrough relief case from mixed alcoholabsorber 50L. This volume may be handled by a relief valve located onthe flash drum. This may avoid the need to evaluate any potential damageto the internals of relatively small diameters of components in thepurification unit 60, due to any high vapor/liquid mixture velocitiesand also may avoid the potential for a two-phase vapor/liquid relief.

In the embodiments described above, the alcohol synthesis unit 10 may ina preferred embodiment comprise a high-pressure main syngas recycleloop, in which the entire syngas recycle loop is at a relatively highpressure compared to the pressure of the rest of the overall process,the step-up in pressure taking place at the syngas compressor 40F. Inthis embodiment, the main recycle loop comprises stream 4034, solventsystem 50A, syngas recycle compressor 50E, alcohol synthesis reactor(s)50H, separator 50L, and stream 5032 which is recycled to mix with stream4034. Syngas recycle compressor 50E may be designed primarily toovercome pressure losses in the loop and keep the main syngas recycleloop circulating.

In an another embodiment, the main syngas recycle loop may be at anintermediate pressure, except for a segment of the loop comprising thesynthesis reactor 50H that operates at a relatively high pressure.Upstream of reactor 50H there may be a high-pressure compressor, anddownstream of the reactor there may be a turbo-expander to reduce thepressure down to the intermediate pressure of the remainder of the loop.In one embodiment, the turbo-expander may drive the high-pressurecompressor from the energy derived from reducing the pressure of the hoteffluent stream to match the intermediate-pressure system. Thisembodiment may include catalyst poison removal separator(s) (e.g., 41G,41F, and 41E of FIG. 6) within the intermediate-pressure portion of themain syngas recycle loop, as preferably these units operate at anintermediate pressure. The intermediate pressure may be between about8.6 bar and about 103.4 bar (about 125 psig and about 1500 psig),preferably between about 27.6-68.9 bar (about 400-1000 psig), and mostpreferably about 37.9-51.7 bar (about 550-750 psig).

FIG. 8 shows an illustrative example of a solvent system 50A. Compressedfresh feed syngas 4034 from the syngas cleanup and compression unit 40may preferably be combined with the recycle gas stream 5032 and sent toa solvent absorber 51A. The combined gas stream preferably enters thebottom of the absorber and flows up through the bottom trayed section ofthe column where it may be contacted with the solvent solution flowingdown through the bottom section to remove CO₂ from the gas stream. Thesyngas then may flow up through a chimney tray into the top tray sectionof the column where the gas is contacted with a circulating wash waterstream flowing down through the top section to recover solvent entrainedin the syngas. An absorber water wash pump 51B may circulate the washwater from the chimney tray to the top of the column. A surge volume ofdemineralized water may be stored in a water make-up drum 51C and thenpumped to the chimney tray with a water make-up pump to provide freshmakeup water. A purge stream may branch off the suction line of thewater circulation pump 51B to maintain the liquid level in on thechimney tray. The purge stream may be sent to a rich solvent flash drum51E.

The solvent absorber 51A is preferably designed with the flexibility tocontrol the CO₂ content in the treated gas between approximately 1 and 5mol % while minimizing the loss of carbon monoxide (CO) and hydrogen(H₂) in the syngas stream. In one illustrative embodiment, approximately15% of the treated syngas exiting the top of the absorber flows (5002)to the electricity generation unit 70 and to a gas turbine generatortherein, and the remainder flows to the recycle compressor 50E.

The rich solvent solution 5003 from the bottom of the solvent absorberMA may be sent to a rich solvent hydraulic turbine MD to recover energyfrom the high-pressure liquid and provide power to one or more leansolvent pumps 51F. The low-pressure rich solvent from turbine MD maycombine with the water wash purge (discussed above), and may alsocombine with condensate stream 5101 from the syngas recycle compressor(FIG. 7, 50D, discussed above), and the combined stream 5212 may flow tothe rich solvent flash drum ME. In this flash drum, preferably themajority of the CO₂ and H₂S absorbed in the combined rich solvent/washwater stream flashes off (5004). The slightly diluted rich solventsolution 5005 then may flow through a lean/rich solvent exchanger MG topreheat the rich solvent before it enters the Solvent Regenerator 51H.The CO₂/H₂S gas stream 5004 from flash drum ME may be sent to the syngasblower 40E utilizing pressure control to maintain sufficient pressure inthe outlet to the syngas blower to allow the rich solvent solution toflow into the solvent regenerator 51H without being pumped.

The rich solvent solution may comprise an amine, and preferablycomprises monoethanol amine. In another embodiment, the solventcomprises dimethyl ethers of polyethylene glycol. Other solvent systemscapable of removing CO₂ and H₂S are known in the art.

Steam may be condensed on the tube side of a solvent regeneratorreboiler 51J to provide heat for stripping at least most of theremaining acid gases from the rich solvent solution. The steamcondensate may be collected in an amine regenerator reboiler steamcondensate drum 51K and then sent to a condensate flash tank.

Lean solvent 5007 from the bottom of regenerator 51H may be pumpedthrough the lean/rich solvent exchanger 51J using a lean solvent boosterpump 51L. A portion of the partially-cooled lean solvent stream may berecycled to the suction of the pump after flowing through a solventfilter package 51M to remove particulates that tend to build up in thecirculating solution. The lean solvent then may flow through the leansolvent cooler 51N for additional cooling utilizing cooling water beforeit is pumped with lean solvent pump 51F back to the top tray in thesolvent section of solvent absorber 51A. As mentioned above, at leastone of the lean solvent pumps may in one embodiment be connected to thesolvent hydraulic turbine 51D to recover energy from the high-pressurerich solution from the absorber and supplement its motor driver.

Overhead vapor 5009 from the regenerator may be partially condensed in asolvent regenerator overhead condenser 51P preferably by heat exchangewith ambient air, and the vapor/liquid stream may enter a solventregenerator overhead knock-out drum 51Q. The majority of the condensedliquid 5011 may be returned to the top of the solvent regenerator 51Hwith a solvent regenerator reflux pump 51R. However, a small waterblowdown stream may be taken from the discharge of the reflux pump 51Rto maintain the water balance in the solvent circulation system, whichmay preferably be sent to a water reclamation unit. Sour gas 5010 (whichmay be primarily CO₂ with a small amount of H₂S) may exit drum 51Q onpressure control, and may in one embodiment be sent to sulfur guard(e.g., 50B and 50C of FIG. 7) to remove H₂S from the stream.

Fresh solvent may be brought into the plant by tank trucks or othermeans of conveyance and transferred to the solvent storage tank 51S. Asolvent make-up pump may be used to pump make-up solvent from storage51S, through a solvent make-up filter, and into the liquid surge sectionof the solvent regenerator 51H as needed. Additionally, an anti-foampackage may be utilized to inject an anti-foam agent into thecirculating wash water stream at the top of solvent absorber MA and thereflux stream at the top of solvent regenerator 51H.

All solvent solution drained from equipment and piping in the solventtreating area may be collected in a drain solvent sump drum 51T. Thedrum may be vented to a flare header and may have a continuous nitrogenpurge. A drain solvent sump drum pump 51U may be utilized tointermittently pump the recovered solvent through the solvent make-upfilter MV and into the liquid surge section of the solvent regenerator51H.

Purification

Mixed alcohols from alcohol synthesis unit 50 may be purified toseparate ethanol in purification unit 60. FIG. 9 illustrates onepossible embodiment of a purification system 60. Mixed alcohol liquidstream 5035, and flash gas 5036 may be sent to mixed alcohol degasser60A. Water 5037 may be used as a reflux stream to strip the majority ofthe alcohol compounds that are present in the vapor. The overhead ventgas 6000 may be recycled to the syngas cleanup and compression unit 40.The mixed alcohols from the bottoms of the degasser 60A may be combinedwith off-specification ethanol 8100 recycled from downstream in theprocess, and may be sent to the methanol-ethanol/heavies separator 60B.This separator may be designed to separate methanol and ethanol in theoverhead or distillate, and propanol, heavier alcohols, and water in thebottoms. A resulting propanol and heavier stream 6023 may be separatedinto heavy alcohol 6026 and water 6029 components in a propanol/waterseparator 60C. The heavy alcohol stream 6026 may preferably be vaporizedin a fusel oil vaporizer 60J and fed to the gasification unit 20, and inone embodiment to a TRC within the gasification unit, where it may bepartially oxidized to form carbon monoxide, hydrogen, carbon dioxide,and water. Water stream 6029 may be sent to the alcohol synthesis unit50. for heat exchange and use in absorbing mixed alcohols from theethanol reactor effluent, as discussed above.

In one embodiment, the vapor product 6003 of column 60B may be condensedin the overhead, for example via heat exchanger 60K, returning part ofthe condensed liquid 6004, and sending another part of the condensedliquid as stream 6007 to methanol/ethanol separator 60D. In thisembodiment, the heat released by overhead condensation may be used toreboil column 60D.

Overhead product 6007 from column 60B may be passed to methanol/ethanolseparator 60D to separate ethanol from lighter components. The overheador distillate 6011 may contain methanol and methyl acetate. Liquidproduct 6012 from column 60D may in one embodiment be reboiled, forexample in exchanger 60K, by utilizing heat of condensation for thevapor stream of column 60B, and returned to the column as stream 6013.The bottoms 6015, preferably containing highly pure ethanol, may beprocessed in an ethanol dehydration unit 60E and then may be processedin a post-distillation treatment unit 60H, to remove sulfur compounds,from which may emerge the final ethanol product 6022. In one embodiment,an ethanol condensate 6100 from the ethanol drying unit 60E may bepassed to the inlet to the methanol-ethanol/heavies separator 60B.

The methanol/methyl acetate stream 6011 may be passed to amethanol/methyl acetate separator 60F where methanol and methyl acetateup to the methanol/methyl acetate azeotrope may be separated and may bestored in methanol storage unit 60G. In one embodiment, methanol 6039may be recycled to the ethanol reactor in the alcohol synthesis unit 50.The methyl acetate stream 6033 may in one embodiment be vaporized in afusel oil vaporizer 60J and fed to the gasification unit 20, preferablyto a TRC, where it may be partially oxidized forming carbon monoxide,hydrogen, carbon dioxide, and some water. The heat required to vaporizefusel oil streams 6033 and/or 6026 may in vaporizer 60J may in oneembodiment be obtained from the outlet 6017 of the ethanol dehydrationunit 60E.

In one embodiment, at least a fraction of methanol 6039 may be sent toan auto-thermal reformer (ATR) for creation of syngas for further use inthe overall process. In one embodiment, only the excess methanol whichcannot be recycled to alcohol synthesis reactor will be sent to the ATR.In another embodiment, at least a fraction of methanol 6039 may be sentback to the vicinity of the outlet of gasification unit 20 (preferablythe outlet of a TRC), and used to quench the hot syngas resulting fromsyngas generation.

An ATR may in one embodiment be used to modulate the H₂:CO ratio in thesyngas of the ethanol reactor. In one embodiment, alcohols, preferablyall alcohols in the system other than ethanol and methanol, and mostpreferably propanol, may be fed into the ATR. Steam may be injected intothe syngas to provide water for a water-gas shift reaction that may takeplace in the ATR. The ATR may also be fed by an oxygen stream 1132. Inone embodiment, the ATR may also be fed by a natural gas or methanestream. Thus, in an optional mode of operation, the ATR may operate byreforming methane with carbon dioxide produced as part of the water-gasshift reaction. This mode of operation may be referred to as anaugmentation step, and may be useful in many situations, such as whenthere is a shortage of syngas, when the gasifier or other syngasproduction facility goes down, or when there is a need for morehydrogen. Optionally, the ATR may be supplied with a carbon dioxide lineto provide carbon dioxide if necessary to balance the amount of naturalgas. Such carbon dioxide might, in one embodiment, be obtained fromanother part of the overall process, such as stream 5015 of FIG. 7.

FIG. 10 shows an illustration of one embodiment of a mixed alcoholdegasser 60A. The mixed alcohol liquid stream 5035, which may have beenpreheated as discussed above, may be sent to the mixed alcohol degasser60A, while flash gas 5036 may also flow to degasser 60A optionallythrough a separate route. The degasser column may preferably be providedwith two packed sections where both the flash gas 5036 and mixed alcoholliquid stream 5035 may preferably enter the column between the packedsections. The lower packed section, if used, may strip the remainingdissolved gases 6000 from the mixed alcohol stream. The reboil heat mayin one embodiment be provided by condensing steam in a mixed alcoholdegasser reboiler 61B to maintain the desired temperature at the bottomof the column. The steam condensate may be collected in a degasserreboiler steam condensate drum 61C and then may be sent to a condensateflash drum. A mixed alcohol degasser bottoms pump 61D may transfer thedegassed mixed alcohol stream 6002 from the bottom of the degassercolumn to an ethanol/heavies column (e.g., 60B of FIG. 9).

The upper packed section of the degasser column may preferably utilize awater stream 5037 to absorb the majority of the alcohol compounds thatmay be present in the combined vapor stream comprising the flash gas5036 entering the column and the stripping vapor from the bottomsection. As discussed above, the water “reflux” stream 5037 may besupplied to the top of the degasser 60A by a small slipstream from adischarge from the alcohol synthesis area 50, and in one embodiment fromabsorber water feed pump 50S (FIG. 7). The water from stream 5037 may inone embodiment originate from stream 6029 as the water componentsseparated from the propanol/water separator 60C (FIG. 9). As discussedabove, the overhead vent gas 6000 from the degasser 60A may in oneembodiment be recycled the syngas cleanup and compression unit 40.

All process liquids drained from equipment and piping from the area maypreferably be collected in an alcohol drain sump drum 61E. The drum mayin one embodiment be vented to the flare header, and may preferably havea continuous nitrogen purge. An alcohol drain sump drum pump 60F may beutilized to intermittently pump the recovered liquid into the suctionline 6001 of the mixed alcohol degasser bottoms pump 61D.

FIG. 11 shows an illustration of one embodiment of an ethanol/heaviesseparator 60B, together with possible related elements. A mixed alcoholstream 6002 may preferably be fed directly to themethanol-ethanol/heavies column 60B where ethanol and lighter components(e.g., methanol) 6003 may be separated from propanol and heaviercomponents (e.g., heavy alcohols and water) 6023. The column may alsopreferably receive a small amount of condensate 6100 recycled fromethanol drying unit 60E. Additionally, when there is a requirement torecycle off-spec ethanol from storage, an off-spec stream 8100 maycombine with the hot mixed alcohol stream before entering theethanol/heavies column 60B. The reboil heat may be provided to thecolumn by condensing steam 7102 in an ethanol/heavies column reboiler62D to maintain the desired temperature at the bottom of the column.Steam condensate may be collected in an ethanol/heavies column reboilersteam condensate drum 62E and then, in one embodiment, sent to acondensate flash drum via 7300.

An ethanol/methanol vapor mixture 6003 may exit the top of the columnand may, in one embodiment, provide reboil heat to a downstreammethanol/ethanol column 60D (FIG. 9, FIG. 13). A partially condensedstream 6004 may be sent to an ethanol/heavies column flash drum 62Fwhere the vapor and liquid may be separated to avoid problems withvertical two-phase flow. The vapor stream from the drum may in oneembodiment flow through a control valve that may be adjusted to maintainthe desired pressure at the top of the column and the liquid stream mayexit the drum on level control. The vapor and liquid streams may then berecombined close to the inlet of an ethanol/heavies column trimcondenser 62G where the remainder of the overhead vapor may in oneembodiment be condensed by heat exchange with ambient air. The outlettemperature from the condenser is preferably controlled by automaticadjustment of the air outlet louvers. The completely condensed overheadstream 6005 may then flow to an ethanol/heavies column reflux drum 62H.The reflux stream 6006 may then be returned to the top of column 60B byan ethanol/heavies column reflux pump 62J on flow control. An overheadethanol/methanol liquid product 6007 may also flow through the refluxpump 62J and be sent to the Methanol/Ethanol Column 60D (FIG. 9, FIG.13) on level control.

A propanol and heavier (e.g., heavy alcohols and water) stream 6023 mayleave the bottom of column 60B on level control and flow to apropanol/water column 60C. In order to accommodate the potential need torecycle off-spec ethanol product through the purification unit 60, themethanol-ethanol/heavies column and its associated equipment maypreferably be designed for an additional capacity above the normal plantdesign rate.

FIG. 12 illustrates one embodiment of a propanol/water separator 60C andpossible related elements. A propanol/water column 60C may preferablyreceive a propanol and heavier (e.g., heavy alcohols and water) stream6023 directly from the bottom of a methanol-ethanol/heavies column 60B.Column 60C may be designed to separate propanol and heavier hydrocarbonsfrom any recyclable absorbent water. Reboil heat may be provided to thecolumn by condensing steam 7102 in a propanol/water column reboiler 62Kto maintain the desired temperature at the bottom of the column. Thesteam condensate may be collected in a propanol/water column reboilersteam condensate drum 62L and then in one embodiment sent to acondensate flash drum via 7300.

A vapor from column 60C, which may comprise propanol, may exit the topof the column and be condensed in a propanol/water column condenser 62M,preferably by heat exchange with ambient air. The outlet temperature ofvapor 6025 from the condenser may in one embodiment be controlled byautomatic adjustment of the air outlet louvers. An overhead stream 6025,which is preferably completely condensed, may then flow to apropanol/water column reflux drum 62N. The pressure at the top of column62C may be automatically maintained by adjusting a control valve inoutlet line 6025 from the condenser. The pressure in reflux drum 62N maybe automatically maintained in various ways, including by eitheradjusting a hot vapor bypass valve around the condenser or ventingnon-condensable gases that accumulate in the drum to a relief header.Reflux 6027 may be returned to the top of column 62C by a propanol/watercolumn reflux pump 62P, which may be on flow control. An overheadliquid, which in one embodiment may comprise predominantly propanol andother fusel oils, may flow through the reflux pump 62P and be sent(6026) to a fusel oil vaporizer 60J (see FIG. 9) to preferablycompletely vaporize the stream before it is preferably recycled back tothe gasification unit 20 (and preferably to a TRC within thegasification unit).

A regenerated recycle water stream 6028 may leave the bottom of column60C and be pumped by a recycle water pump 62Q as stream 6029 to thealcohol synthesis unit 50, as discussed above, for eventual for reuse ina mixed alcohol absorber 50L (see FIG. 7).

FIG. 13 illustrates one embodiment of a methanol/ethanol separator 60Dand associated elements. A methanol/ethanol column 60D may receive anethanol/methanol stream 6007. The column may preferably be designed toseparate methanol and other light components from the ethanol product.As mentioned earlier, hot overhead vapor 6003 from an ethanol/heaviescolumn 60B may in one embodiment be used to reboil the liquid product6012 from column 60D column in methanol/ethanol column reboiler 60K(returning to the column as stream 6013). In one embodiment, varying theamount of the hot vapor bypassing the reboiler may provide temperaturecontrol for the bottom of the column. This heat integration between thetwo columns is preferable to conserve steam that would otherwise berequired for the reboil heat.

A vapor 6008, preferably predominately methanol, may exit the top ofcolumn 60D and be condensed in a methanol/ethanol column condenser 63Aby heat exchange with ambient air. The outlet temperature from thecondenser may be controlled by automatic adjustment of the air outletlouvers. The preferably completely condensed overhead stream 6009 maythen flow to a methanol/ethanol column reflux drum 63B. The pressure atthe top of the column may preferably be automatically maintained byadjusting a control valve in the outlet line from the condenser. Thepressure in the reflux drum 63B may be automatically maintained in manyways, including by either adjusting a hot vapor bypass valve around thecondenser or venting non-condensable gases that may accumulate in thedrum to a relief header. Reflux 6010 may be returned to the top of thecolumn by a methanol/ethanol column reflux pump 63C on flow control. Theoverhead liquid may also flow through the reflux pump 63C and be sent(via 6011) to a methanol/methyl acetate column 60F.

An ethanol product stream 6014 may leave the bottom of the column and bepumped for further processing by the ethanol pump 63D. In order toaccommodate the potential need to recycle off-spec ethanol product 8100through purification unit 60, the methanol/ethanol column 60D and itsassociated equipment may preferably be sized and designed for additionalcapacity above the normal plant design rate.

FIG. 14 shows an illustration of one embodiment of a methanol/methylacetate separator 60F, methanol storage unit 60G, and associated units.A methanol/methyl acetate column 60F may receive a stream 6011, which ispreferably predominantly methanol. The column 60F may preferably bedesigned to remove methyl acetate from the methanol stream so that themethanol may preferably be recycled to the gasification unit 50. Thereboil heat may be provided to the column by condensing steam 7102 in amethanol/methyl acetate column reboiler 64A to maintain the desiredtemperature at the bottom of the column. A steam condensate may becollected in a methanol/methyl acetate column reboiler steam condensatedrum 64B and then sent to a condensate flash drum (via 7300).

A predominately methyl acetate vapor 6030 may exit the top of the columnand be condensed in a methanol/methyl acetate column condenser 64C byheat exchange with ambient air. The outlet temperature from thecondenser may be controlled in one embodiment by automatic adjustment ofthe air outlet louvers. An overhead stream, which may preferably becompletely condensed, may then flow to a methanol/methyl acetate columnreflux drum 64D. The pressure at the top of the column is automaticallymaintained by adjusting a control valve in the outlet line from thecondenser. The pressure in the reflux drum is automatically maintainedby either adjusting the hot vapor bypass valve around the condenser orventing non-condensable gases that accumulate in the drum to the reliefheader. Reflux 6032 may be returned to the top of the column by amethanol/methyl acetate column reflux pump 64E on flow control. Anoverhead liquid 6033, which is preferably predominantly methyl acetate,may also flow through reflux pump 64E and be combined with fusel oil,preferably to sent to the gasification unit 20.

A methanol stream 6036 may exit the bottom of the column and be pumpedby a methanol/methyl acetate column bottoms pump 64F then conveyed(6037) through a methanol cooler 64G where it may be cooled by exchangewith ambient air and then sent (6038) to a methanol storage tank 60G.The outlet temperature from the cooler may preferably be controlled byautomatic adjustment of the air outlet louvers.

A methanol storage tank 60G may receive a cooled methanol stream 6038.The tank may be blanketed with nitrogen to prevent air from migratinginto the tank. Any vapors that may leave the tank as it is being filledmay be vented to the atmosphere at a safe location. The methanol 6039may preferably then be pumped by a methanol recycle pump 64H to alcoholsynthesis unit 50 where it may combine with the syngas stream prior toan inlet of a reactor (see, e.g., FIG. 7).

FIG. 15 illustrates one embodiment of a sulfur removal unit 60H, andethanol storage and handling unit 80, and related elements. After beingpumped from the bottom of a methanol/ethanol column (e.g., 60D), anethanol liquid 6015 may flow through an ethanol vaporizer 65A where itmay be vaporized and superheated by condensing steam 7102. The steamcondensate 7300 may be collected in an ethanol dryer vaporizer steamcondensate drum 65B and then sent (7300) to a condensate flash drum. Theethanol vapor 6016 then may flow through one or more ethanol dryers 65Cto remove water in the stream to meet the desired ethanol productspecification. Two or more ethanol dryers may preferably be provided inorder to have at least one dryer in operation and at least one dryer inregeneration mode. In one embodiment, the overhead of ethanol dryer 65Cmay be condensed and then recycled to a point upstream in thepurification unit 60. Preferably, the overhead may be cooled inexchanger 65D, preferably by cooling water, then separated into a vaporand liquid in a flash drum 65E. The vapor may be pumped (65F),preferably to flare 6200. The liquid 6100 may preferably be recycled toa point upstream of ethanol/heavies separator 60B.

Following dehydration the ethanol vapor may in one embodiment be passedover a sorbent such as SULFATREAT SELECT ULTRA (provided by M-I SWACO),or activated carbon in another embodiment, to adsorb various organicsulfur compounds including sulfides, di-sulfides and mercaptans. Thispost distillation treatment system may reduce the total sulfur in theethanol product stream sufficiently to meet ASTM product purityrequirements.

Dry ethanol vapor 6017 may in one embodiment be used to vaporize fuseloil in the fusel oil vaporizer 60J, as discussed earlier. Preferably,final condensing and cooling of the ethanol product 6019 occurs in anethanol condenser 65G by heat exchange with ambient air. The temperaturein the outlet 6020 from the condenser may preferably be controlled byautomatic adjustment of the air outlet louvers.

The cooled ethanol product liquid 6020 may flow to an ethanol productreceiver 65H that may preferably operate under a nitrogen blanket andpreferably vent (6200) to a flare header on high pressure. Ethanol maythen be pumped from the receiver by an ethanol product transfer pump 65Jto one or more sulfur adsorbent beds 65K for the removal of trace sulfurcompounds. In one embodiment, two adsorbent beds may be piped in alead/lag configuration to allow for on-line replacement of spentadsorbent. The treated ethanol product may then flow through an ethanolfilter 65L to remove any adsorbent fines from the product stream beforeit is routed to ethanol storage and treatment unit 80.

In order to accommodate the potential need to recycle off-spec ethanolproduct through purification unit 60, the components of the purificationunit 60 may preferably be designed for an additional capacity above thenormal plant design rate.

Ethanol storage and treatment unit 80 may include at least one or morevessels for storing ethanol, facilities to allow product testing andmeasurement, preferably with pumps and valves configured to allow therecycling of off-spec ethanol 8100 back to purification 60.

Electricity Generation

FIG. 16 illustrates one embodiment of an electricity generation unit 70which may generate electricity from steam, natural gas, and/or syngas.In the alcohol synthesis unit 50, in one embodiment approximately 15% ofthe syngas (5002) may be combusted with air 7400 in combustion turbine70A. In a preferred embodiment, natural gas 7450 is also used inaddition to syngas 5002 as fuel for gas turbine 70A. The combustionturbine may be linked to a generator 70C that may produce power for theplant. During normal operation, the combustion turbine may preferably bedesigned to operate fully loaded to maximize power generation. Turbineexhaust gas 3235 may flow through a gas turbine heat recovery steamgenerator (HRSG) 70B to recover heat from the hot gas stream by, in oneembodiment, (70E) preheating high-pressure boiler feed water 7100 forone or more reactors (via 5103) in the alcohol synthesis unit 50, (70F)preheating the medium-pressure boiler feed water 7103 supply to the HRSGsteam drum 70E, (70G) generating saturated steam preferably at about 800psig and (70H) superheating the preferably about 55.2 bar (about 800psig) steam it produces 3103. After flowing through the HRSG, the cooledexhaust gas 3250 may preferably be vented to the atmosphere through avent stack. The steam drum 70E may preferably be supplied withcontinuous and/or intermittent blowdown facilities to maintain the waterquality. The continuous and/or intermittent blowdown streams maypreferably be routed separately to blowdown drums.

All of the preferably 55.2 bar (800 psig) steam 3100 that may besuperheated in the waste heat recovery unit 30, and all the steam 3103that may be generated in the gas turbine HRSG 70A, may preferably besent to the steam turbine 70J and generator 70K to generate power.However, in one embodiment, a portion of the steam 3650 may first passthrough a heater (e.g., 50G of FIG. 7) upstream of an alcohol synthesisreactor in the alcohol synthesis unit 50, before returning as stream3652 and entering the steam turbine 70J at an interstage. The steamturbine 70J may in one embodiment operate as a total condensing turbineutilizing (1) a steam turbine condenser 70L, (2) a steam turbinecondenser hot well pump 70M, and (3) a steam turbine after condenser 70Nwhich may preferably use blowdown and/or other waste water from variousparts of the overall process as coolant. The clean condensate from theafter condenser may preferably be sent directly to a plant deaerator andthen reused in various parts of the facility.

Reactor Configuration and Chemistry

Alcohol synthesis reactors (e.g., 50H in FIG. 7) for use in thisdisclosure may take many forms consistent with the claims definedherein. In a preferred embodiment, two ethanol synthesis reactors 50Hmay be provided with each train consisting of two reactors in series,for a total of four reactors. Preferably, the reactors are packed bedtubular reactors containing a moly-sulfide catalyst. Each reactor trainmay be sized for 50% of the total design syngas rate. In each reactor,the syngas may contact catalyst as it flows down through the tubesinside of the reactor.

Any suitable catalytic reactor may be used. In some embodiments thereactor may include a plurality of tubes filed with one or more mixedalcohol catalysts. In an exemplary embodiment, the reactor may be in avertical downflow configuration with a plurality of elongated, 2-inch(5.08 cm) outer diameter tubes filed with the catalyst.

Table 2 presents the design and operating parameters for oneillustrative embodiment of one of the reactors.

TABLE 2 Approximate design parameters for an ethanol reactor in oneillustrative embodiment of the disclosure. Gas Hourly Space Velocity4000 hr⁻¹ Reactor Diameter 3.81 meters (12.5 feet) Catalyst Depth inTubes 6.096 meters (20 feet) Number of Tubes 2440 Tube Diameter 5.08 cmO.D. (2″ O.D.) Tube Side Outlet Temperature 350° C. (662° F.) Tube SideOperating Pressure 103.4 bar (1500 psig) Shell Side Operating 254-271°C. Temperature (489-520° F.) Shell Side Operating Pressure 82.7-103.4bar (1200-1500 psig)

In the reactor(s), the following water gas shift reaction may occur:

CO+H₂O

CO₂+H₂

The water gas shift reaction is slightly exothermic in the direction ofproducing carbon dioxide and hydrogen. In addition, reactor conditionsmay be provided so that some or all of the following catalyzed reactionsoccur:

CO+3H₂→CH₄+H₂O  (methane)

2CO+5H₂→C₂H₆+2H₂O  (ethane)

CO+2H₂→CH₃OH  (methanol)

2CO+4H₂→C₂H₅OH+H₂O  (ethanol)

3CO+6H₂→C₃H₇OH+2H₂O  (propanol)

3CO+4H₂→CH₃COOCH₃+H₂O  (methyl acetate)

Other reactions may also occur, and some of the reactions listed abovecan go in both directions depending on the various equilibriumconditions.

While the gasification reaction in the gasification unit 20 may createone hydrogen molecule for every carbon monoxide molecule, the productionof ethanol requires twice as many hydrogen molecules as carbon monoxidemolecules. The additional hydrogen may be produced in the water gasshift reaction, at the expense of producing carbon dioxide. In thepreferred embodiment, carbon dioxide may be removed from the processthrough a separation unit such as the solvent system 50A (shown in FIG.7). The removal of carbon dioxide from the stream passing through thereactor(s) may push the equilibrium of the water gas shift reaction infavor of producing hydrogen, which in turn may result in the productionof more ethanol.

As discussed above, in some embodiments, to maximize the production ofethanol from syngas, unconverted syngas and methanol may be recycledfrom the purification unit 60 to a point upstream of the alcoholsynthesis reactor(s). This methanol may be converted to ethanol in thereactor(s) by the following reaction:

CH₃OH+CO+2H₂→C₂H₅OH+H₂O.

In addition, propanol and higher alcohols, as well as methyl acetate,may be recycled to the gasification unit 20 and may be cracked toproduce additional syngas.

Methane, ethane, and other light gases may also be produced in thereactor(s). At least some of these light gasses may be recycled with theunreacted syngas. In one embodiment, at least some of these gases may bepurged from the main reactor loop by diversion of a portion of thesyngas to a combustion turbine 70A for use in generating electricity. Inanother embodiment, at least some of the methane and/or ethane may bereformed by, for example, the use of an autothermal reformer, accordingto the following reactions:

2CH₄+O₂+CO₂→3H₂+3CO+H₂O

C₂H₆+O₂+CO₂→2H₂+3CO+H₂O.

In another embodiment, at least some of the methane, ethane, and otherlight gases may follow the methanol through purification unit 60, andmay be recycled to the reactor(s) with the methanol. In anotherembodiment, at least some of the methane, ethane, and other light gasesmay be separated from recycle syngas through a separator dedicated forthat purpose. An overall process may make use of any or all of the abovealternative embodiments simultaneously. In yet another embodiment,methane, ethane, and other hydrocarbons may be converted to syngas in acatalytic reformer downstream of the gasification unit 20, by meansknown in the art.

The heat released from the various reactions in the alcohol synthesisreactor(s) may be transferred to water, preferably on a shell side ofthe reactor(s). Preferably, this water may be flashed to steam asdescribed above. Additional heat and energy may be recovered from thereactor effluent, as described above.

Certain reactor conditions may have a direct impact on the yield ofethanol formed from syngas in catalytic alcohol synthesis processes suchas those described in the present disclosure. The reactions occurring inthe alcohol synthesis reactor(s) may be equilibrium reactions at a givenset of conditions. By manipulating certain reactor conditions, thesereactions can either move to form more complex or less complexmolecules.

More specifically, it has been determined there are a number ofsynthesis reactor conditions which may have a direct impact on theyields of ethanol and other alcohols. These conditions may include anyone or more of: partial pressures of reactants, diluents, temperature,pressure, gas hourly space velocity (GHSV) and the amount of methanolrecovered in the effluent from the reactor and recycled back to thereactor. Without being bound by any particular theory, it is useful toconsider methanol to be a building block for the production of ethanol,and to consider ethanol in turn to be a building block for higheralcohols.

In one exemplary and non-limiting embodiment, at a specific temperatureand pressure, if the gas hourly space velocity (GHSV) is increased, themolar ratio and mass yields of the synthesis reaction products can beselectively controlled such that formation of methanol and/or ethanolmay be increased, and formation of the heavier alcohols may bedecreased.

It is most useful to consider GHSV, temperature, and pressure to the bethe primary determinants of reactor efficiency and productivity, ratherthan the volume of catalyst. Surprisingly, one may achieve essentiallythe same performance of an alcohol synthesis reactor over a wide rangeof catalyst volumes. Thus, it may be possible to minimize the amount ofcatalyst volume and therefore save cost.

In some embodiments, the GHSV may be at or above about 2,000 hr⁻¹. Inother embodiments, the GHSV may be in the range of about 2,000 to 10,000hr⁻¹ or higher, or preferably within the range of about 3,000 to about7,000. The reactions that convert syngas components to alcohol compoundsare exothermic and may cause the temperature of the syngas to increaseas it flows through the catalyst. In one embodiment, the syngas mayenter the first reactor in each train at about 315.5° C. (about 600° F.)and the temperature of the reactants may be allowed to increase to about350° C. (662° F.). In other embodiments, the core temperature of thecatalyst may be in a range of about 315.5° C. to about 371° C. (600° F.to about 700° F.). The pressure may preferably be about 103.5 bar (about1500 psig), or within a range such as 68.9 to 137.9 bar (1000 to 2000psig). The GHSV, temperature, and pressure may be optimized, or furtheroptimized from the ranges described above, to achieve the desired COconversion and ethanol selectivity.

In some embodiments, methanol may be introduced along with syngas intothe reactor inlet to increase the formation of ethanol from the reactionof hydrogen and carbon monoxide. In an exemplary embodiment, the molarratio of hydrogen to carbon monoxide (H₂:CO) in the reactor inlet streammay be in the range of about 0.7:1 to about 2.0:1, more preferablyapproximately 1.5:1. In embodiments where two or more reactors are usedand configured in series, methanol may be feed to one or more of thereactors by injecting methanol between the reactors.

In one embodiment, the ethanol reactor(s) may convert syngas intoethanol utilizing a catalyzed thermochemical conversion. Examples ofsuitable catalysts are described in WO 2009/009389 A2 (published Jan.15, 2009) and WO 2009/009388 A2 (published Jan. 15, 2009), which areincorporated herein by reference in their entirety. Preferably, thereactor(s) may use a catalyst that may convert methanol to ethanol andhigher alcohols, or that may convert syngas and/or methanol selectivelyinto ethanol. Suitable catalysts that may promote the formation ofethanol and/or higher alcohols are also known in the art, and may forexample include ZnO/Cr₂O₃, Cu/ZnO, Cu/ZnO/Al₂O₃, CuO/CoO, CuO/CoO/Al₂O₃,Co/S, Mo/S, Co/Mo/S, Rh/Ti/SiO₂, Rh/Mn/SiO₂, Rh/Ti/Fe/Ir/SiO₂,Rh/Mn/MCM-41, Ni/S, Ni/Mo/S, Ni/Co/Mo/S and any of the foregoing incombination with Mn and/or V. The catalyst may also include one or morebasic promoters, such as potassium, alkaline-earth, and rare-earthmetals.

Sulfided catalysts have many advantages known in the art, including theadvantage of being sulfur-tolerant, which may reduce the cost ofcleaning the syngas upstream of the reactor. In a preferable embodiment,the reactor(s) use a may use a CoS_(i)/MoS_(i)/NiS_(i) catalyst. In oneembodiment, the catalyst charged to the reactor(s) may contain about12-16 wt. % Mo, about 1-2 wt. % Ni, about 4-6 wt. % Co, and about 6-8wt. % potassium, with the remainder being activated carbon. Preferably,the catalyst may contain about 14 wt. % Mo, about 1.5 wt. % Ni, about4.5 wt. % Co, and about 7.2 wt. % potassium, with the remainder beingactivated carbon. The catalyst may preferably be sulfidized by injectinga sulfur donor compound such as H₂S or dimethyl sulfide into the syngasstream that passes through the reactor(s). Sulfidization may preferablyoccur on a continuous basis. Production and use of a suitable class ofCoS_(i)/MoS_(i)/NiS_(i) catalysts is described in U.S. ProvisionalApplication No. 61/159,780 (filed Mar. 12, 2009) and applicationsclaiming priority thereto.

In one embodiment, reactors using different catalysts may be joined inseries, or a single reactor may have different zones containingdifferent catalysts. For example, a reactor containing a catalyst thatpromotes the formation of methanol may precede a reactor containing acatalyst that promotes the formation of ethanol and/or higher alcoholsfrom methanol. The entire reactor may also, in one embodiment, comprisethe latter catalyst. Thus, an embodiment may comprise a methanolcatalyst and a mixed alcohol catalyst arranged in series, among otherpossible arrangements, or two mixed alcohol catalysts arranged inseries. Suitable catalysts that may promote the formation of methanolare known in the art, and may for example include ZnO/Cr₂O₃, Cu/ZnO,Cu/ZnO/Al₂O₃, Cu/ZnO/Cr₂O₃, Cu/ThO₂, Co/S, Mo/S, Co/Mo/S, Ni/S, Ni/Mo/S,Ni/Co/Mo/S, and any of the foregoing in combination with Mn and/or V.The catalyst may also include one or more basic promoters, such aspotassium, alkaline-earth, and rare-earth metals, but such promoter mayalso be omitted to increase selectivity toward methanol.

In one embodiment, the alcohol synthesis unit 50 may comprise tworeactors in series. Preferably, methanol 6039 may be injected into amixing point between the two reactors, so that the recycle methanolbypasses the upstream reactor and combines with syngas to flow into thedownstream reactor. The catalyst in each of the two reactors may be thesame, or each reactor may have a different catalyst. In an alternateembodiment, instead of two separate reactors, the alcohol synthesis unit50 may comprise two reaction zones within a single reactor, and methanolmay be injected into a space between the two reaction zones.

Exemplary embodiments have been described with reference to specificconfigurations. The foregoing description of specific embodiments andexamples of the invention have been presented for the purpose ofillustration and description only, and although the invention has beenillustrated by certain of the preceding examples, it is not to beconstrued as being limited thereby.

1. A facility for converting organic materials into ethanol comprising:a feedstock separator, configured to separate non-organic materials froma solid feedstock which may optionally contain entrained liquids,thereby creating a solid processed feedstock; a gasification unitconfigured to generate a primary syngas from the processed feedstock; awaste heat recovery system comprising a heat exchanger configured togenerate superheated steam by cooling a stream comprising the primarysyngas, thus outputting a cooled primary syngas stream; means forconveying the primary syngas to the waste heat recovery system; a steamturbine and generator configured to use the superheated steam togenerate electricity; one or more syngas scrubbers configured to removeor neutralize one or more unwanted contaminants from the cooled primarysyngas stream, thereby to create a scrubbed syngas; a syngas compressorconfigured to raise the pressure of a compressor inlet stream comprisinga first portion of the scrubbed syngas to a predefined level, therebyoutputting a compressed gas stream; an alcohol synthesis reactor,comprising a catalyst, in fluid communication with the syngas compressorand configured to take at least a portion of the compressed gas streamas an input and produce an effluent comprising unconverted syngas and amixture of reaction products including alcohols and water; apurification unit configured to separate at least a portion of theeffluent into a number of streams comprising: an ethanol streamcomprising primarily ethanol; a stream comprising primarily water; amethanol stream comprising primarily methanol; and a heavy alcoholstream comprising primarily propanol and heavier alcohols; a quenchrecycle loop comprising: the means for conveying the primary syngas tothe waste heat recovery system, which comprises a mixing point upstreamof the waste heat recovery system; the waste heat recovery system; andquench recycle means for conveying to the mixing point a first portionof a quench recycle stream consisting of either at least a portion ofthe cooled primary syngas stream or at least a portion of the scrubbedsyngas stream; a valve configured to regulate flow through the firstportion of the quench recycle means; a temperature sensor configured tomeasure the temperature of the syngas downstream of the mixing point;and a controller configured to control the valve in response to thereading of the temperature sensor to maintain the temperature near apredetermined temperature value.
 2. The facility of claim 1, wherein thepredefined temperature value is between about 650° C. to about 760° C.3. The facility of claim 2, wherein the predefined temperature value isabout 760° C.
 4. The facility of claim 1, wherein the quench recycleloop further comprises a quench recycle compressor of sufficient powerto circulate syngas gas through the quench recycle loop.
 5. The facilityof claim 4, wherein the quench recycle compressor comprises a pluralityof stages, one or more inter-stage heat exchangers configured to coolthe inter-stage syngas, and one or more knock-out drums.
 6. The facilityof claim 4, wherein the quench recycle compressor comprises a pluralityof compressors arranged in parallel.
 7. The facility of claim 4, furthercomprising: means for conveying a second portion of the quench recyclestream to a mixing point upstream of the inlet of the compressor; avalve configured to regulate flow through the second portion of thequench recycle means; a pressure sensor configured to measure thepressure of the syngas downstream of the mixing point; and a controllerconfigured to control the valve in response to the reading of thepressure sensor to maintain the pressure near a predetermined valueabove atmospheric pressure.
 8. The facility of claim 7, wherein thepredefined pressure value is less than about 1 bar over atmospheric. 9.The facility of claim 1, further comprising: a mercury-lead separatorconfigured to remove mercury or lead or both mercury and lead from amercury-lead separator inlet stream comprising at least a portion ofsyngas downstream of the waste heat recovery system; wherein the one ormore syngas scrubbers comprises one or more scrubbers configured toremove particles and to neutralize acidic compounds from the cooledprimary syngas stream, to create the scrubbed syngas; wherein the quenchrecycle loop further comprises the one or more syngas scrubbers but notthe mercury-lead separator; and wherein the quench recycle streamconsists of a second portion of the scrubbed syngas.
 10. The facility ofclaim 9, wherein the syngas compressor comprises: one or more initialcompressor or compressor stages comprising an outlet; one or more finalcompressor or compressor stages, configured to output the compressed gasstream, comprising an inlet; means for conveying the mercury-leadseparator inlet stream from the outlet to the mercury-lead separator;means for conveying gas from the mercury-lead separator to the inlet.11. A method for converting organic materials into ethanol comprising:separating non-organic materials from a solid feedstock which mayoptionally contain entrained liquids, thereby creating a solid processedfeedstock; generating a primary syngas from the processed feedstock in agasification unit; generating superheated steam by cooling a streamcomprising the primary syngas in a heat exchanger, thus outputting acooled primary syngas stream; generating electricity from thesuperheated steam; removing or neutralizing one or more unwantedcontaminants from the cooled primary syngas stream, thereby creating ascrubbed syngas; compressing a compressor inlet stream comprising afirst portion of the scrubbed syngas, thereby raising the pressure ofthe compressor inlet stream to a predefined level, and outputting acompressed syngas; providing conditions, including the presence of acatalyst, to cause components of at least a portion of the compressedsyngas to react and produce an effluent comprising unconverted syngasand a mixture of reaction products including alcohols and water; andseparating at least a portion of the effluent into a number of streamscomprising: an ethanol stream comprising primarily ethanol; a streamcomprising primarily water; a methanol stream comprising primarilymethanol; and a heavy alcohol stream comprising primarily propanol andheavier alcohols; wherein the step of generating superheated steam takesplace within one or more heat exchangers comprising a waste heatrecovery inlet for the stream comprising the primary syngas, furthercomprising: conveying at a defined recycle flow rate, to a mixing pointupstream of the waste heat recovery inlet, a first portion of a quenchrecycle stream consisting of either at least a portion of the cooledprimary syngas stream or at least a portion of the scrubbed syngasstream; measuring the temperature of the stream comprising the primarysyngas; and controlling the recycle flow rate to maintain thetemperature near a predetermined temperature value.
 12. The method ofclaim 11, wherein the predetermined temperature value is between about650° C. to about 760° C.
 13. The method of claim 12, wherein thepredetermined temperature value is about 760° C.
 14. The method of claim11, wherein the step of conveying further comprises: pumping the quenchrecycle stream in a plurality of stages; and between at least two of thestages, cooling the syngas and collecting condensate from the syngas inone or more knock-out drums.
 15. The method of claim 11, wherein thestep of conveying further comprises pumping with a compressor, furthercomprising: conveying, at a defined spillback flow rate, a secondportion of the quench recycle stream to a mixing point upstream of theinlet of the compressor; measuring the pressure near the inlet of thecompressor; controlling the spillback flow rate to maintain the pressurenear a predetermined pressure value above atmospheric pressure.
 16. Themethod of claim 15, wherein the predetermined pressure value is lessthan about 1 bar over atmospheric.
 17. The method of claim 11, furthercomprising: removing mercury or lead or both mercury and lead from amercury-lead separator inlet stream comprising at least a portion ofsyngas cooled by the heat exchanger, thus producing a mercury-leadseparator outlet stream; wherein the step of removing or neutralizingone or more unwanted contaminants comprises removing particles andneutralizing acidic compounds from the cooled primary syngas stream, tocreate the scrubbed syngas; wherein the quench recycle stream consistsof at least a second portion of the scrubbed syngas.
 18. The method ofclaim 17, wherein the step of compressing comprises: compressing thecompressor inlet stream in one or more initial compressors or compressorstages, to create an initial compressed stream, wherein the mercury-leadseparator inlet comprises at least a portion of the initial compressedstream; compressing a stream comprising at least a portion of themercury-lead separator outlet stream in one or more final compressors orcompressor stages, to create the compressed syngas.